KELLEY OIL & GAS CORP, 10-K, 1998-03-30

KELLEY OIL & GAS CORP
10-K, 1998-03-30
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, 1997 COMMISSION FILE NO. 0-25214

KELLEY OIL & GAS CORPORATION
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)

DELAWARE 76-0447267
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)

601 JEFFERSON - SUITE 1100
HOUSTON, TEXAS 77002
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)

REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (713) 652-5200

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

TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
------------------- -----------------------------------------
8 1/2% Convertible Subordinated American Stock Exchange
Debentures due 2000

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

TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
Common Stock Nasdaq National Market
$2.625 Convertible Exchangeable Nasdaq National Market
Preferred Stock

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

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

As of March 24, 1998, 125,709,593 shares of Common Stock and 1,745,443 shares of
Preferred Stock were outstanding, and the aggregate market values of shares held
by unaffiliated stockholders were approximately $116,554,368 and $43,586,075,
respectively.

DOCUMENTS INCORPORATED BY REFERENCE

Certain portions of the Proxy Statement for the 1998 Annual Meeting of
Stockholders are incorporated by reference into Part III of this Report.

<PAGE>
PART I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

INTRODUCTION

Kelley Oil & Gas Corporation, incorporated in Delaware in 1994, 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.

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. Accordingly,
historical financial and reserve information presented in this document for
periods before the Consolidation reflects Kelley Oil's historical results on a
stand-alone basis prior to the Consolidation, with the results of the Company's
combined operations recorded thereafter. 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, formerly President and Chief Executive Officer of Shell Oil Company,
was appointed Chairman, President and Chief Executive Officer of the Company,
and certain

1
<PAGE>
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. Proceeds from the Contour Transaction, after repayment
of bank debt, plus funds available under the Company's bank credit facility
("Credit Facility") have permitted the Company to continue drilling operations
and permitted it to pursue acquisition opportunities needed to execute its
business strategy for replacing its production and expanding its reserves.

INDUSTRY PARTNERSHIP. Pursuant to the terms and conditions of a joint
venture with a unit of The Williams Companies, Inc., ("Williams") effective
December 1, 1996, Williams purchased an undivided 50% interest in the Company's
interest in its 27,000 net acreage position as well as 50% of the Company's
interest in 23 wells and related facilities in this area (including Orange
Grove/Humphreys and Ouiski Bayou fields), in Terrebonne Parish, Louisiana. The
total purchase price was $20.5 million, a portion of which was committed under
the joint venture to drill up to eight exploration prospects in such area.
Pursuant to the joint venture, the Company and Williams are conducting an
exploratory drilling program on their south Louisiana properties.

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.

OPERATIONS AND PROPERTIES

OPERATION ACTIVITIES. The Company's core production is derived from four
contiguous fields in the Vacherie Salt Dome region of north Louisiana. The
Company's remaining production is generally from the shallow waters of the Gulf
of Mexico, south Louisiana and east Texas.

DEVELOPMENT ACTIVITIES. The Company continues development drilling
activities within its existing core properties in the Vacherie Salt Dome region
of north Louisiana, where at December 31, 1997, approximately 73% of the its
proved reserves were located on 48,060 gross (22,075 net) acres. The Company
presently intends to continue dedicating a significant share of its capital
resources to these properties. The Company drilled or participated in drilling
82 gross (35 net) development wells in 1997, all of which were completed as
producing wells. The Company also intends to continue the development of the
proved undeveloped portions of the newly-acquired SPR Properties and south
Louisiana properties, primarily in Terrebonne Parish.

EXPLORATION ACTIVITIES. The Company focuses its exploration activities
on its existing leaseholdings in Terrebonne and LaFourche Parishes, the shallow
waters of the Gulf of Mexico, and the Permian Basin, which the Company believes
have, with higher risk, the potential for larger reserve and production
increases as compared to development activity in north Louisiana. The Company
has approximately 331,800 gross undeveloped acres of exploratory properties
principally in these regions on which it has identified over 30 prospective
exploratory well sites, that it believes is a two to three year inventory of
exploration prospects based on its current rate of planned capital expenditures.
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 drilling rigs, availability of capital, weather, and general
economic factors. See "Caution as to Forward-Looking Statements" and "Risk
Factors".

2
<PAGE>
The Company is utilizing current technologies to identify exploration
prospects and advanced geophysical techniques to continue to re-evaluate 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
plans to participate in 3-D seismic surveys covering approximately 135 square
miles in south Louisiana and east Texas.

In 1997, the Company drilled 10 gross (4.0 net) exploratory wells, of
which 9 gross (3.5 net) were completed as producing wells. Included in these
amounts are 4 gross (1.0 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
principally in Louisiana, and in the Gulf of Mexico, Texas, New Mexico and
Arkansas. As of January 1, 1998, the Company owned interests in a total of 513
gross (249.6 net) producing wells, of which 295 wells were operated by the
Company, accounting for 79% of its current production. As of that date, the
Company had leaseholdings covering 241,550 gross (98,052 net) developed acres
and 622,641 gross (56,356 net) undeveloped acres. Approximately 95% of its
proved oil and natural gas reserves as of January 1, 1998, was natural gas on an
energy content basis. The reserves to production ratio for these properties
(based on 1997 production rates) was estimated to be 11.8 as of January 1, 1998.

SIGNIFICANT PROPERTIES. The Company's core natural gas properties in
north Louisiana are located in the Sailes, Sibley, West Bryceland and Ada fields
of Webster and Bienville Parishes, while its core properties in south Louisiana
are concentrated in the Orange Grove/Humphreys, Lirette, Lake Paige and Ouiski
Bayou fields in Terrebonne Parish, and the Fire Island field in Vermilion
Parish. Production is primarily from the Hosston (north Louisiana) and Miocene
(south Louisiana) formations. The SPR 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."

SIGNIFICANT PROVED PROPERTIES
<TABLE>
<CAPTION>
PROVED RESERVES AT JANUARY 1, 1998 PRODUCTION(1)
------------------------------------------- ------------------------------
YEAR ENDED
PRESENT VALUE DECEMBER 31, 1997
OF ESTIMATED ------------------------------
GAS FUTURE NET GAS
OIL GAS EQUIVALENT CASH FLOWS(2) OIL GAS EQUIVALENT
MBBLS MMCF (MMCFE) (IN THOUSANDS) (MBBLS) (MMCF) (MMCFE)
------ ------- ----------- ------------- ------ ------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
North Louisiana............ 620 269,320 273,040 $245,366 95 26,411 26,981
South Louisiana............ 425 18,216 20,766 29,463 58 1,543 1,891
Offshore................... 460 27,983 30,743 38,040 9 544 598
Other as a group........... 1,448 39,348 48,036 65,942 64 1,704 2,088
------- -------- -------- ------- ----- ------- -------
Totals..................... 2,953 354,867 372,585 $378,811 226 30,202 31,558
======= ======== ======== ======== ===== ======= =======
</TABLE>
- ------------
(1) Production from the SPR Properties is included in these amounts
since the closing and effective date of the acquisition, December 1, 1997.

(2) 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 10 to the Consolidated Financial Statements.

ADDITIONAL INFORMATION REGARDING THESE REGIONS IS SET FORTH BELOW.
UNLESS OTHERWISE NOTED, ACREAGE AND WELL INFORMATION IS PROVIDED AS OF DECEMBER
31, 1997, AND RESERVE INFORMATION IS PROVIDED AS OF JANUARY 1, 1998.

NORTH LOUISIANA. The Company's operations in this region are 70% 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.
Recently, increases in estimated ultimate recoveries from north

<PAGE>
Louisiana wells have been achieved from revised interpretations of geological
fault systems, revised fracture stimulation techniques and regulatory changes
that allow the commingling of production from multiple zones. The Company's
reserves to production ratio in north Louisiana is approximately 10.1. Its
lifting costs in this region are generally low (approximately $0.12 per Mcfe in
1997) 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 $0.56 per Mcfe with gross
average reserves per well of 3.1 Bcfe. At December 31, 1997, the Company
operated an aggregate of 176 gross (95.4 net) wells in this region and was
drilling or completing 8 gross (4.5 net) wells in the region, all of which were
subsequently completed as producing wells. The Company's average working
interest in these properties is approximately 37%.

SOUTH LOUISIANA. The Company's operations in this region primarily are
focused on five fields in the Houma Embayment area and one field in nearby
Vermilion Parish. The Houma Embayment is composed of high-quality reservoir
rock, contributing to high production rates. Wells are typically drilled to a
depth of approximately 11,000 to 17,000 feet. The present value of estimated
future net cash flows at December 31, 1997 (calculated in accordance with
Securities and Exchange Commission ("SEC") guidelines - see Note 10 to the
Consolidated Financial Statements for further discussion) attributable to the
Company's reserves in south Louisiana was approximately $29.5 million, of which
90% are proved developed. The Company's south Louisiana properties generally are
located in close proximity to transportation and market locations, and
production therefrom generally receives higher prices because of its rich
condensate content. The Company believes these factors partially offset the
higher operating costs associated with higher formation pressures, salt water
disposal and inland water well locations associated with the region. At December
31, 1997, the Company operated an aggregate of 15 gross (7.7 net) wells and was
drilling 1 gross (0.5 net) well in this region that was subsequently plugged
and abandoned. The Company's average working interest in these properties is
approximately 43%.

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 estimates the current net production from these properties
to be approximately 24 Mmcfe per day. The present value of estimated future net
cash flows at December 31, 1997 (calculated in accordance with SEC guidelines -
see Note 10 to the Consolidated Financial Statements for further discussion) in
this region was $38.0 million, of which 100% are developed. At December 31,
1997, the Company operated an aggregate of 33 gross (29.9 net) wells in this
region and had an interest in 50 gross (33.9 net) wells with an average working
interest of approximately 46%.

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,
1995, 1996 and 1997, which were prepared by H.J. Gruy & Associates, Inc.
("Gruy") independent petroleum engineers.

4
<PAGE>
ESTIMATED PROVED RESERVES
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------------
1995 1996 1997
----------------- ---------------- ---------------
OIL GAS OIL GAS OIL GAS
(MBBLS) (MMCF) (MBBLS) (MMCF) (MBBLS) (MMCF)
-------- ------- ------- ------- ------- ------
<S> <C> <C> <C> <C> <C> <C>
PROVED RESERVES:
Beginning balance.........................1,236 93,612 1,387 196,273 1,466 297,634
Revisions of previous estimates..........(1,324) (64,027) (89) (30,519) 106 21,831
Purchases of reserves in place............1,756 127,962 57 30,844 1,351 51,712
Extensions and discoveries................ 156 66,864 477 128,692 256 13,892
Sale of reserves in place................. (118) (10,388) (134) (4,190) -- --
Production................................ (319) (17,750) (232) (23,466) (226) (30,202)
----- ------- ----- ------- ----- -------
Ending balance..........................1,387 196,273 1,466 297,634 2,953 354,867
===== ======= ===== ======= ===== =======
PROVED DEVELOPED RESERVES:

Producing................................. 669 63,488 608 113,831 1,856 180,307
Non-producing............................. 528 47,799 369 59,634 576 77,493
----- ------ ----- ------ ----- ------
Total proved developed..................1,197 111,287 977 173,465 2,432 257,800
===== ======= ===== ======= ===== =======
</TABLE>
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.

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 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.

5
<PAGE>
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 1995, 1996 and 1997. Detailed additional information concerning the
Company's oil and natural gas production activities is contained in the
Supplementary Information in Note 10 to the Consolidated Financial Statements
included elsewhere in this Report.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------
1995 1996 1997
------- ------- ------
<S> <C> <C> <C>
PRODUCTION DATA:
Oil and other liquid hydrocarbons (Mbbls)................... 319 232 226
Natural gas (Mmcf).......................................... 17,750 23,466 30,202
Natural gas equivalent (Mmcfe).............................. 19,664 24,858 31,558
AVERAGE SALES PRICE PER UNIT:

Oil and other liquid hydrocarbons (per Bbl).................$ 17.37 $ 22.11 $ 19.34
Natural gas (per Mcf, including effects of hedging)......... 1.71 2.30 2.27
Natural gas equivalent (per Mcfe, including effects
of hedging)............................................... 1.83 2.37 2.31
AVERAGE PRODUCTION EXPENSES PER MCFE.......................... .55 .43 .35
</TABLE>
PRODUCTIVE WELLS AND ACREAGE

As of December 31, 1997, the Company had leaseholdings comprising 241,550
gross (98,052 net) developed acres and 622,641 gross (56,356 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.

The following table sets forth the Company's ownership interests in its
leaseholds as of December 31, 1997.
<TABLE>
<CAPTION>
DEVELOPED(1) UNDEVELOPED(2)
-------------------------- --------------------------
GROSS ACRES NET ACRES GROSS ACRES NET ACRES
------------ ------------ ------------ -----------
<S> <C> <C> <C> <C>
Louisiana................................... 89,975 40,428 304,615 33,012
Texas....................................... 81,444 30,788 138,962 4,909
Offshore.................................... 25,007 5,947 3,575 758
Other states................................ 45,124 20,889 175,489 17,677
------- ------- -------- -------
Total.................................... 241,550 98,052 622,641 56,356
======= ======= ======== =======
</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, 1997, the Company had working interests in 464 gross
(225.2 net) productive gas wells and 49 gross (24.4 net) productive oil wells
(including producing wells and wells capable of production).

6
<PAGE>
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 during the
periods indicated.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------------
1995 1996 1997
------------- ------------- -------------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C>
NORTH LOUISIANA:
Exploratory wells:
Oil..................................... -- -- -- -- -- --
Natural gas.............................. -- -- -- -- -- --
Dry..................................... -- -- -- -- -- --
----- ----- ----- ----- ----- -----
Total................................... -- -- -- -- -- --
===== ===== ===== ===== ===== =====
Development wells:
Oil..................................... 1 .05 1 .03 -- --
Natural gas............................. 22 9.26 65 31.63 82 34.96
Dry..................................... -- -- 3 1.74 -- --
----- ----- ----- ----- ----- -----
Total................................. 23 9.31 69 33.40 82 34.96
===== ===== ===== ===== ===== =====
Total north Louisiana:
Producing............................... 23 9.31 66 31.66 82 34.96
Dry..................................... -- -- 3 1.74 -- --
----- ----- ----- ----- ----- -----
Total................................. 23 9.31 69 33.40 82 34.96
===== ===== ===== ===== ===== =====
SOUTH LOUISIANA AND OTHER:
Exploratory wells:
Oil..................................... -- -- -- -- -- --
Natural gas............................. -- -- -- -- 9 3.50
Dry..................................... 1 .95 -- -- 1 0.50
----- ----- ----- ----- ----- -----
Total................................. 1 .95 -- -- 10 4.00
===== ===== ===== ===== ===== =====
Development wells:
Oil..................................... -- -- -- -- -- --
Natural gas............................. 4 3.78 -- -- -- --
Dry..................................... 1 .95 -- -- -- --
----- ------- ----- ----- ----- -----
Total................................. 5 4.73 -- -- -- --
===== ===== ===== ===== ===== =====
Total south Louisiana and other:
Producing............................... 4 3.78 -- -- 9 3.50
Dry..................................... 2 1.90 -- -- 1 0.50
----- ----- ----- ----- ----- -----
Total................................. 6 5.68 -- -- 10 4.00
===== ===== ===== ===== ===== =====
</TABLE>
As of December 31, 1997, the Company had 8 gross (4.5 net) development
wells in progress, all in north Louisiana, and 1 gross (0.5 net) exploratory
well in progress in south Louisiana. Subsequent to year-end 1997, all of these
wells were completed as producing wells except the south Louisiana exploratory
well which was plugged and abandoned.

7
<PAGE>
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.

8
<PAGE>
EMPLOYEES

As of December 31, 1997, the Company had 57 employees. The Company
expects to add approximately 18 employees during 1998 who were formerly
associated with SPR's operations. 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. Most states in which the Company owns and operates properties have
regulations governing conservation matters, including provisions for the
unitization or pooling of oil and natural gas properties, the establishment of
maximum rates of production from oil and natural gas wells and the regulation of
the spacing, plugging and abandonment of wells. Many states also restrict
production to the market demand for oil and natural gas and several states have
indicated interest in revising applicable regulations. The effect of these
regulations is to limit the amount of oil and natural gas the 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, as

9
<PAGE>
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.

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

10
<PAGE>
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.

LEVERAGE. As of December 31, 1997, the Company had $298.0 million face
amount of debt outstanding and stockholders' deficit of approximately $5.6
million. The Company expects to incur additional indebtedness for future
borrowings under its credit facility as it continues its strategy for
acquisition, exploration and development of oil and gas reserves. The Company's
ability to make scheduled payments of principal, to pay interest on or to
refinance its indebtedness for money borrowed depends on its future performance
and successful implementation of its strategy, which is subject not only to its
own actions but also to general economic, financial, competitive, legislative,
regulatory and other factors beyond its control, as well as to the prevailing
market prices for oil, natural gas and natural gas liquids.

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 and are
expected to continue to be volatile in the future. The prices received by the
Company for its oil, natural gas and natural gas liquids production and the
levels of such production are

11
<PAGE>
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. At present, the level of drilling activity in the
United States has resulted in increased demand for, and therefore increased
costs associated with, drilling equipment and the services and products of other
vendors to the industry. In particular, in connection with drilling activities
in the marshy regions of south Louisiana, there has been an increased cost of
drilling operations due to increased costs for barge rigs necessary to conduct
activity in such region. Moreover, the number of drilling contractors offering
barge drilling and workover services is limited.

The availability of a ready market for 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.

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 1997.

12
<PAGE>
PART II

ITEM 5. MARKET FOR THE COMPANY'S SECURITIES AND RELATED STOCKHOLDER MATTERS

The Company's Common Stock and Preferred Stock are traded on the NASDAQ
National Market under the symbols "KOGC" and "KOGCP." Prior to the
Consolidation, Kelley Oil's common stock ("KOIL Common Stock") and $2.625
convertible exchangeable preferred stock ("KOIL Preferred Stock") were traded on
the NASDAQ Stock Market under the symbols "KOIL" and "KOILP." The price ranges
presented below represent high and low sale prices for each quarter, as reported
by the NASDAQ Stock Market. The reported prices reflect the commencement of
trading in the Company's Common Stock and Preferred Stock immediately after the
Consolidation on February 8, 1995.

KOIL COMMON STOCK KOIL PREFERRED STOCK
MARKET PRICES MARKET PRICES
------------------- --------------------
HIGH LOW HIGH LOW
------- ------- -------- -------
1995:
First quarter.................. $4 7/8 $ 3 3/4 $21 $18 3/4
Second quarter................. 6 3/8 4 1/4 25 1/2 20 1/4
Third quarter.................. 5 7/8 2 3/4 24 3/8 16 1/2
Fourth quarter................. 3 1/4 15/16 18 1/2 5 1/2

KOGC COMMON STOCK KOGC PREFERRED STOCK
MARKET PRICES MARKET PRICES
-------------------- --------------------
HIGH LOW HIGH LOW
-------- ------- ------- --------
1996:
First quarter ................. $3 5/16 $ 1 $ 18 3/4 $ 6 3/4
Second quarter................. 4 2 3/16 22 5/8 15 1/4
Third quarter.................. 4 1/8 2 9/16 26 20 3/8
Fourth quarter................. 3 1/4 2 7/16 25 23 3/4

1997:
First quarter ................. $3 1/16 $ 1 7/8 $25 3/4 $23 3/4
Second quarter................. 3 1/16 1 11/16 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
(through March 24, 1998)...... $2 23/32 $ 1 7/8 $25 3/4 $21

As of the January 31, 1998, there were approximately 1,665 record
holders of Common Stock and 217 record holders of Preferred Stock.

Dividends on the Preferred Stock accrue quarterly at the rate of $.65625
per share. Three quarterly dividends on the Preferred Stock were paid at that
rate commencing on May 1, 1995. In January 1996, the Company announced the
suspension of dividend payments on the Preferred Stock to conserve cash. 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. The Company's existing credit facility and the Company's indenture
governing its 10 3/8% Senior Subordinated Notes (the "10 3/8% Notes") restricts
the payment of future preferred dividends. As of February 1, 1998, the total
amount of dividend payments in arrears was approximately $5.7 million.

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<PAGE>
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. 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,
--------------------------------------------------
1993 1994 1995 1996 1997
------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Oil and gas revenues........................$21,064 $ 16,822 $ 36,998 $60,854 $75,864
Interest and other income................... 1,506 1,416 1,763 1,429 274
------- -------- -------- ------- -------
Total revenues ......................... 22,570 18,238 38,761 62,283 76,138
------- -------- -------- ------- -------
Production expenses......................... 3,993 3,760 10,835 10,709 10,955
Exploration expenses........................ 14,226 7,404 23,387 5,438 5,433
General and administrative expenses......... 4,079 5,172 7,030 8,953 6,875
Interest and other debt expenses............ 6,638 4,571 21,956 24,401 25,071
Restructuring expenses...................... -- 1,814 1,115 4,276 --
Depreciation, depletion and amortization.... 18,857 20,474 35,591 20,440 25,853
Impairment of oil and gas properties(1)..... -- -- 150,138 -- --
------- -------- -------- ------- -------
Income (loss) before income taxes and
extraordinary item........................(25,223) (24,957) (211,291) (11,934) 1,951
Provision (benefit) for taxes............... -- -- -- -- --
------- -------- -------- ------- -------
Net income (loss) before extraordinary item.(25,223) (24,957) (211,291) (11,934) 1,951
Extraordinary loss(2)....................... -- -- -- (17,030) --
------- -------- -------- ------- -------
Net income (loss)..........................$(25,223) $(24,957)$(211,291) $(28,964) $ 1,951
======== ======== ========= ======== =======
Loss per common share before
extraordinary item(3)....................$ (1.63) $ (1.58) $ (5.31) $ (.18) $ (.03)
Loss per common share(3)...................$ (1.63) $ (1.58) $ (5.31) $ (.37) $ (.03)
Average common shares outstanding.......... 15,967 17,653 41,032 90,113 100,757

AS OF DECEMBER 31,
--------------------------------------------------
1993 1994 1995 1996 1997
-------- -------- -------- -------- --------
BALANCE SHEET DATA:
Property and equipment, net...............$58,018 $ 74,912 $128,642 $158,468 $293,613
Long term debt, excluding current
maturities.............................. 34,814 37,242 164,980 184,253 286,183
Stockholders' equity (deficit)............ 27,415 45,180 (45,568) (30,535) (5,621)
Total assets.............................. 87,145 106,513 151,342 189,227 322,602
</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
$0.9 million, $2.9 million, $6.6 million, $4.6 million and $4.6 million for the
years ended December 31, 1993, 1994, 1995, 1996 and 1997, respectively.

14
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

The following information should be read in conjunction with the
information contained in the Financial Statements of the Company included
elsewhere in this Report.

GENERAL

INTRODUCTION. Kelley Oil & Gas Corporation and its consolidated
subsidiaries (the "Company") are engaged in oil and natural gas exploration,
development, production and acquisition. Effective as of December 1, 1997, the
Company purchased substantially all of the assets of SCANA Petroleum Resources,
Inc. ("SPR") for approximately $110 million, which was financed through a $27
million equity investment in the Company and the incurrence of $83 million in
bank debt. The assets acquired include interests in proved oil and natural gas
reserves primarily located in the shallow waters of the Gulf of Mexico,
Louisiana, and east Texas, as well as exploratory properties in leasehold
acreage in those areas and in the Permian Basin in west Texas and New Mexico. In
addition to its oil and gas development and producing activities, the Company
markets natural gas and operates natural gas gathering and transportation
systems in Louisiana.

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
1997, 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, approximately 65% of the
Company's natural gas production for 1997 was affected by its hedging
transactions at an average NYMEX quoted price of $2.35 per Mmbtu before
transaction and transportation costs. As of December 31, 1997, approximately 29%
of the Company's anticipated natural gas production for 1998 has been hedged by
natural gas price swap agreements at an average NYMEX quoted price of $2.30 per
Mmbtu before transaction and transportation costs. Certain natural gas price
swap agreements outstanding at December 31, 1997 permit the counterparty to
double the contract volume at a specified price. If this feature is exercised on
all contracts outstanding at December 31, 1997, approximately 40% of the
Company's anticipated natural gas production for 1998 has been hedged by natural
gas price swap agreements at an average NYMEX quoted price of $2.31 per Mmbtu
before transaction and transportation costs. In addition, as of December 31,
1997, the Company has outstanding natural gas basis swap agreements covering
approximately 34% of its anticipated natural gas production for January 1998
through September 1998. Hedging activities decreased revenues by approximately
$4.2 million in 1997 as compared to estimated revenues had no hedging activities
been conducted. At December 31, 1997, the unrealized gain on the Company's
existing hedging instruments for future production months in 1998 approximated
$1.4 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.

RESULTS OF OPERATIONS

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

15
<PAGE>
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.

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
last year, 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 last year, 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. On 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 last year. The reasons for the
earnings improvement are described in the foregoing discussion.

YEAR ENDED DECEMBER 31, 1996 COMPARED TO YEAR ENDED DECEMBER 31, 1995.
The Company's oil and natural gas revenues of $60.9 million for 1996 increased
65% compared to $37.0 million for 1995 as a result of increased natural gas
prices and a 32% increase in natural gas production to 23.5 Mmcf in 1996. The
average price of natural gas increased 35% to $2.30 per Mcf in 1996 from $1.71
per Mcf in 1995. The Company's production of natural gas steadily declined
during the second and third quarters of 1995 as a result of poor drilling
results in south Louisiana. During the fourth quarter of 1995, the Company's
prior management implemented a significant reduction in drilling activity, which
adversely affected production in the first half of 1996. The Company's current
accelerated drilling program increased production substantially in the second
half of 1996. Production of crude oil and natural gas liquids during 1996
totaled 232,000 barrels with an average sales price of $22.11 per barrel
compared to 319,000 barrels at $17.37 per barrel in 1995; representing a volume
decrease of 27% and a price increase of 27%. The decline in oil and condensate
volumes was due to the decline in south Louisiana gas production.

16
<PAGE>
Production expenses for 1996 decreased 1% to $10.7 million from $10.8
million in 1995. On a unit basis, production expenses decreased 22% from $0.55
per Mcfe in 1995 to $0.43 per Mcfe in 1996, reflecting lower average costs on
production from north Louisiana, which increased in proportion to other higher
cost production from south Louisiana.

Exploration expenses totaled $5.4 million in 1996 and $23.4 million in
1995, a decrease of 77%, primarily as a result of a temporary suspension of
exploratory drilling pending negotiation of a joint exploration agreement in
south Louisiana. The decrease in this activity also reflected lower geological
and geophysical expenses and unproved leasehold impairment costs.

General and administrative expenses of $9.0 million in 1996 increased
29% compared to $7.0 million in 1995. The increase in expense was primarily
attributable to bonuses and interim salaries paid in connection with the Contour
Transaction to certain members of the Company's prior management team and a
decrease in the level of general and administrative expenses capitalized or
charged to exploration expense. The amounts capitalized or charged to
exploration expense were $3.3 million in 1996 compared to $6.2 million in 1995.
On a unit basis, general and administrative expenses were $0.36 per Mcfe in 1995
and 1996.

Interest and other debt expenses of $24.4 million in 1996 increased 11%
from $22.0 million in 1995. The increase in interest expense resulted primarily
from higher interest rates under the 13 1/2% Senior Notes than under the $90.0
million of bank debt refinanced with proceeds from the offering of the 13 1/2%
Senior Notes in June 1995 and higher average debt levels during 1996. Interest
expense on the 13 1/2% Senior Notes was recorded for approximately ten months in
1996 compared to six months in 1995. In October 1996 the 13 1/2% Senior Notes
were replaced with the 10 3/8% Notes. Included in its 1996 interest expense were
non-cash charges of $2.1 million for amortization of debt issuance costs, $0.9
million for accretion of note discount, $2.0 million for accretion of debt
valuation discount and $0.1 million in imputed interest associated with the
acquisition of oil and natural gas properties.

DD&A decreased 43% from $35.6 million in 1995 to $20.4 million in 1996
despite the increase in production during 1996, primarily as a result of lower
depletion rates following impairment charges aggregating $150.1 million
recognized in the fourth quarter of 1995 against the carrying value of the
Company's oil and natural gas properties 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") and an increase in
quantities of proved developed reserves. On a unit basis, DD&A for oil and
natural gas activities decreased from $1.79 per Mcfe in 1995 to $0.80 per Mcfe
in 1996.

The Company's cost-cutting measures during 1996 included a $4.3 million
restructuring charge in 1996 associated primarily with staff reductions and
related severance settlements with certain employees and various reorganization
costs.

The Company recognized net losses before extraordinary items of $(11.9)
million in 1996 and $(211.3) million in 1995. The reasons for the earnings
improvement are described in the foregoing discussion.

LIQUIDITY AND CAPITAL RESOURCES

GENERAL. The Company's liquidity is materially affected by cash flows
generated from its oil and gas production and was adversely affected in years
prior to 1996 by unsuccessful drilling results on high risk prospects in south
Louisiana. In addition, high interest expense and restrictions under the
Company's debt instruments after the Consolidation limited the Company's ability
to fund drilling projects. These restrictions required the Company to suspend
preferred stock dividends and seek a substantial equity infusion in early 1996
to avoid a financial covenant default under the credit agreement in effect at
that time. This effort resulted in the Contour Transaction, completed in
February 1996. The Contour Transaction allowed the Company to retire its
outstanding bank debt, secure a new banking facility and improve its working
capital position.

Although the Contour Transaction and the debt refinancings have provided
the Company with the means to continue its drilling operations with the
objective of increasing its cash flow and reserves, the Company had $298.0
million face amount of debt outstanding as of December 31, 1997, requiring $26.9
million in annual cash interest payments. Although dividends are restricted
under the Company's existing credit facility and are restricted under the
indenture for the 10 3/8% Senior Subordinated Notes (the "Indenture"), the
outstanding preferred stock is cumulative, requires dividends to accumulate

17
<PAGE>
currently at the rate of $4.6 million annually and carries liquidation
preferences over the Common Stock totaling $49.0 million at December 31, 1997,
including such dividend arrearages. 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. The Company has not declared the
quarterly dividends of $0.65625 for February 1, 1997, May 1, 1997, August 1,
1997, November 1, 1997 and February 1, 1998 aggregating approximately $5.7
million.

LIQUIDITY. Net cash provided by operating activities, before working
capital adjustments, during 1997 aggregated $37.5 million. Funds used in
investing activities were comprised of capital expenditures of $53.1 million and
acquisition expenditures for the SPR properties of $111.1 million. Funds
provided by financing activities were comprised primarily of net principal
borrowings of $97.8 million on the bank credit facility and $27.5 million from
the sale of common stock, partially offset by the payment of $4.6 million of
preferred stock dividends. As a result of these activities, cash and cash
equivalents decreased from $4.1 million at December 31, 1996 to $0.2 million as
of December 31, 1997. As of December 31, 1997, the Company had a working capital
deficit of $15.2 million, compared to a working capital deficit of $6.0 million
at the end of 1996. The balance of the working capital deficit will be funded
through operations and/or bank borrowings.

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.
<TABLE>
<CAPTION>
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
----------------------------------
1995 1996 1997
------- -------- -----
<S> <C> <C> <C>
Net cash provided by operating activities before
working capital adjustments.............................$ 1,765 $ 23,214 $37,534
Net cash used in investing activities.....................(43,224) (53,392) (164,275)
EBITDAX(1)................................................ 20,896 42,621 58,308
</TABLE>
- -----------------
(1) EBITDAX is calculated as net income (loss) before extraordinary items,
excluding interest expense and other debt expenses, income taxes, exploration
costs, restructuring expense, depletion, depreciation, amortization, and
impairment of oil and gas properties. EBITDAX is not a measure of cash flow as
determined by GAAP. The Company has included information concerning EBITDAX
because EBITDAX is a measure used by certain investors in determining a
company's historical ability to service its indebtedness. EBITDAX should not be
considered as an alternative to, or more meaningful than, net income or cash
flow as determined in accordance with GAAP as an indicator of the Company's
operating performance or liquidity. EBITDAX is not necessarily comparable to a
similarly titled measure of another company.

CAPITAL RESOURCES. The credit facility provides for a maximum $140
million revolving credit loan and matures, with all amounts owed thereunder
becoming due and payable, effective December 1, 2000. Borrowings under the
credit facility are subject to a borrowing base to be determined semi-annually
by the lenders (based in part on the proved oil and gas reserves and other
assets of the Company) which may be redetermined more frequently at the election
of the lenders or the borrowers. The borrowing base at December 31, 1997 was
$138.0 million, including an overadvance of $23.0 million. At the time of the
next borrowing base determination, which is expected to be no earlier than May
1, 1998, this overadvance is scheduled to be excluded from the borrowing base
effective June 1, 1998. At December 31, 1997, $111.3 million of borrowings and
$4.3 million of letters of credit were outstanding under the credit facility.

CAPITAL COMMITMENTS. The Company's 1998 capital expenditure budget
provides for $31 million to be expended on development drilling primarily in
north Louisiana and $31 million to be expended on exploratory prospects
primarily in south Louisiana, the shallow waters of the Gulf of Mexico, Texas
and New Mexico. During 1997, the Company participated in drilling 92 gross (39.0
net) wells, of which 91 gross (38.5 net) wells were completed. The 1997 drilling
performance reflects lower risk operations in north Louisiana and exploratory
successes in south Louisiana. The Company, with its partners, continues
exploration activities in south Louisiana. As of the end of the year, the
Company was participating in the drilling or completing of 9 gross (5.0 net)
wells, of which 8 gross (4.5 net) wells were subsequently completed as producing
wells.

18
<PAGE>
Effective as of December 1, 1997, the Company purchased substantially
all of the assets of SPR for approximately $110 million. The purchase price of
SPR was funded in part through a $27 million equity contribution from Contour
Production Company L.L.P. ("Contour"). This equity contribution was made
pursuant to the voluntary exercise of its February 1996 option agreement
("Contour Option") to purchase 27 million shares of the Company's common stock
at an exercise price of $1.00 per share. The balance of the funding was provided
through bank financing.

In addition, the Company has an active program for ongoing evaluation of
opportunities meeting its acquisition criteria. There can be no assurance that
attractive acquisition candidates will be available to the Company on terms it
deems reasonable or that any completed acquisition will ultimately prove to be a
successful undertaking by the Company.

The Company has planned in 1998 to fund its debt service obligations,
capital expenditure requirements and working capital needs through cash flows
from operations and borrowings under the revolving credit facility. The
Company's plans are predicated on cash flow assumptions utilizing commodity
prices in the range realized in 1997. Material increases or decreases in natural
gas prices, which are highly volatile, will impact the Company's cash flows and
its ability to carry out its 1998 capital program. The Company may be required
to pursue additional financing alternatives to fully realize its objectives for
property development and acquisitions.

The Company does not anticipate that it will incur any significant
expenditures to address Year 2000 issues, nor do Year 2000 issues represent a
known material event or uncertainty to the Company. To the extent that the
Company may be adversely affected by the Year 2000 issues of its suppliers,
customers and other entities, the Company does not believe that it will be more
adversely affected than other companies in its industry with similar operations.

INFLATION AND CHANGING PRICES. Oil and natural gas prices, as with most
commodities, are highly volatile, have fluctuated during recent years and
generally have not followed the same pattern as inflation. The following table
shows the changes in the average oil and gas prices received by the Company
during the periods indicated.

AVERAGE AVERAGE
OIL PRICE GAS PRICE
($/BBL) ($/MCF)
----------- -----------
YEAR ENDED:
December 31, 1997...........................$ 19.34 $ 2.27
December 31, 1996........................... 22.11 2.30
December 31, 1995 .......................... 17.37 1.71

19
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES: PAGE
Independent Auditors' Report ...................................... 21
Consolidated Balance Sheets - December 31, 1996 and 1997 .......... 22
Consolidated Statements of Income (Loss) - For the years
ended December 31, 1995, 1996 and 1997 .......................... 23
Consolidated Statements of Cash Flows - For the years
ended December 31, 1995, 1996 and 1997 .......................... 24
Consolidated Statements of Changes in Stockholders' Equity
(Deficit) - For the years ended
December 31, 1995, 1996 and 1997 ............................... 25
Notes to Consolidated Financial Statements ........................ 26

20
<PAGE>
INDEPENDENT AUDITORS' REPORT

To the Board of Directors and Stockholders of Kelley Oil & Gas Corporation

We have audited the accompanying consolidated balance sheets of Kelley
Oil & Gas Corporation and subsidiaries as of December 31, 1996 and 1997, and the
related consolidated statements of income (loss), cash flows, and changes in
stockholders' equity (deficit) for each of the three years in the period ended
December 31, 1997. 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, 1996 and 1997, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1997, in conformity with generally accepted accounting principles.

As discussed in Note 1 to the consolidated financial statements, in 1995
the Corporation changed its method of accounting for the impairment of
long-lived assets to conform with Statement of Financial Accounting Standards
No. 121.

DELOITTE & TOUCHE LLP

Houston, Texas
March 6, 1998

21
<PAGE>
KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

(IN THOUSANDS, EXCEPT SHARE DATA)
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------
1996 1997
-------- --------
<S> <C> <C>
ASSETS:
Cash and cash equivalents.............................................$ 4,070 $ 162
Accounts receivable................................................... 22,519 24,566
Accounts receivable - drilling programs............................... 1,533 718
Prepaid expenses and other current assets............................. 1,347 1,412
-------- --------
Total current assets................................................ 29,469 26,858
-------- --------
Oil and gas properties, successful efforts method:
Unproved properties, net............................................ 12,521 49,854
Properties subject to amortization.................................. 338,794 463,263
Pipelines and other transportation assets, at cost ................... 4,689 4,690
Furniture, fixtures and equipment..................................... 1,700 2,969
-------- --------
357,704 520,776

Less: Accumulated depreciation, depletion and amortization...........(199,236) (227,163)
-------- --------
Total property and equipment, net................................... 158,468 293,613
Other non-current assets, net......................................... 1,290 2,131
-------- --------
Total assets........................................................$189,227 $322,602
======== ========
LIABILITIES:

Accounts payable and accrued expenses.................................$ 31,093 $ 41,474
Accounts payable - drilling programs.................................. 4,416 566
-------- --------
Total current liabilities........................................... 35,509 42,040
-------- --------
Long term debt........................................................ 184,253 286,183
-------- --------
Total liabilities................................................... 219,762 328,223
-------- --------
COMMITMENTS AND CONTINGENCIES

STOCKHOLDERS' DEFICIT:
Preferred stock, $1.50 par value, 20,000,000 shares
authorized at December 31, 1996 and 1997;
1,745,500 and 1,745,443 shares issued and
outstanding at December 31, 1996 and 1997, respectively
(liquidation value $48,219 and $48,977, respectively)............... 2,618 2,618
Common stock, $.01 par value, 200,000,000 shares
authorized at December 31, 1996 and 1997;
98,293,457 and 125,709,093 shares issued and
outstanding at December 31, 1996 and 1997, respectively............. 983 1,257
Additional paid-in capital............................................ 273,096 300,367
Accumulated deficit...................................................(307,232) (309,863)
-------- --------
Total stockholders' deficit......................................... (30,535) (5,621)
-------- --------
Total liabilities and stockholders' deficit.........................$189,227 $322,602
======== ========
</TABLE>
See Notes to Consolidated Financial Statements.

22
<PAGE>
KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (LOSS)

(IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------
1995 1996 1997
--------- -------- --------
<S> <C> <C> <C>
REVENUES:
Oil and gas revenues..................................$ 36,998 $ 60,854 $ 75,864
Interest and other income............................. 1,763 1,429 274
--------- -------- --------
Total revenues........................................ 38,761 62,283 76,138
--------- -------- --------
COSTS AND EXPENSES:
Production expenses................................... 10,835 10,709 10,955
Exploration expenses.................................. 23,387 5,438 5,433
General and administrative expenses................... 7,030 8,953 6,875
Interest and other debt expenses...................... 21,956 24,401 25,071
Restructuring expenses................................ 1,115 4,276 --
Depreciation, depletion and amortization.............. 35,591 20,440 25,853
Impairment of oil and gas properties.................. 150,138 -- --
--------- -------- --------
Total expenses........................................ 250,052 74,217 74,187
--------- -------- --------
Income (loss) before income taxes and extraordinary item (211,291) (11,934) 1,951
Income taxes.......................................... -- -- --
--------- -------- --------
Net income (loss) before extraordinary item............. (211,291) (11,934) 1,951
Extraordinary item.................................... -- (17,030) --
--------- -------- --------
Net income (loss)....................................... (211,291) (28,964) 1,951
Less: cumulative preferred stock dividends............ (6,607) (4,582) (4,582)
--------- -------- --------
Net loss applicable to common stock.....................$(217,898) $(33,546) $ (2,631)
========= ======== ========
Loss per common share before extraordinary item.........$ (5.31) $ (.18) $ (.03)
========= ======== ========
Loss per common share ..................................$ (5.31) $ (.37) $ (.03)
========= ======== ========
Average common shares outstanding....................... 41,032 90,113 100,757
========= ======== ========
</TABLE>
See Notes to Consolidated Financial Statements.

23
<PAGE>
KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------
1995 1996 1997
--------- --------- -------
<S> <C> <C> <C>
OPERATING ACTIVITIES:
Net income (loss).....................................$(211,291) $ (28,964) $ 1,951
Adjustments to reconcile net income (loss) to net cash
provided by (used in) operating activities:
Depreciation, depletion and amortization............ 35,591 20,440 25,853
Impairment of oil and gas properties................ 150,138 -- --
Gain on sale of properties.......................... (777) (176) --
Exploration expenses................................ 23,387 5,438 5,433
Accretion and amortization of other debt expenses... 3,602 5,170 4,297
Restructuring expenses.............................. 1,115 4,276 --
Extraordinary loss.................................. -- 17,030 --
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable
and other current assets.......................... 9,457 (9,054) (1,297)
Decrease (increase) in other non-current assets..... 3,075 (1,945) (1,203)
Increase (decrease) in accounts payable and
accrued expenses.................................. (16,103) (2,953) 4,570
--------- --------- ---------
Net cash provided by (used in) operating activities... (1,806) 9,262 39,604
--------- --------- ---------
INVESTING ACTIVITIES:
Capital expenditures.................................. (52,240) (47,601) (53,140)
Acquisition of oil and gas properties................. -- (11,594) (111,135)
Cash received in consolidation........................ 1,596 -- --
Proceeds from sale of properties...................... 7,420 5,803 --
--------- --------- ---------
Net cash used in investing activities................. (43,224) (53,392) (164,275)
--------- --------- ---------
FINANCING ACTIVITIES:
Proceeds from long term borrowings.................... 37,100 50,000 180,500
Principal payments on long term borrowings............ (100,000) (58,500) (82,700)
Proceeds from sale of notes, net...................... 95,302 120,938 --
Debenture conversion costs............................ -- (1,100) --
Proceeds from sale of common stock, net............... 16,319 43,998 27,545
Retirement of senior notes............................ -- (113,488) --
Dividends on preferred stock.......................... (6,607) -- (4,582)
--------- --------- ---------
Net cash provided by financing activities............. 42,114 41,848 120,763
--------- --------- ---------
Decrease in cash and cash equivalents................... (2,916) (2,282) (3,908)
Cash and cash equivalents, beginning of period.......... 9,268 6,352 4,070
--------- --------- ---------
Cash and cash equivalents, end of period................$ 6,352 $ 4,070 $ 162
========= ========= =========
</TABLE>
See Notes to Consolidated Financial Statements.

24
<PAGE>
KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (DEFICIT)

(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
ADDITIONAL
PREFERRED COMMON PAID IN ACCUMULATED
STOCK STOCK CAPITAL DEFICIT
----------- ---------- ---------- -----------
<S> <C> <C> <C> <C>
Stockholders' equity at January 1, 1995........$ 7,743 $ 177 $ 98,647 $ (60,366)

Additional paid in capital from issuance of
preferred and common stock in consolidation.. -- -- 108,632 --
Issuance of 650 shares of preferred stock,
$1.50 par value, in consolidation........... 975 -- -- --
Issuance of 20,622 shares of common stock
in consolidation............................ -- 206 -- --
Issuance of 4,000 shares of common stock
in private placement......................... -- 40 15,960 --
Conversion of 1,508 shares of preferred
stock into 1,508 shares of common stock...... (2,262) 15 2,247 --
Issuance of 225 shares of common stock
pursuant to employee incentive stock options. -- 2 318 --
Syndication costs.............................. -- -- -- (4)
Preferred stock dividends...................... -- -- -- (6,607)
Net loss....................................... -- -- -- (211,291)
--------- --------- --------- ---------
BALANCE AT DECEMBER 31, 1995................. 6,456 440 225,804 (278,268)
--------- --------- --------- ---------

Issuance of 48,000 shares of common stock in
Contour Transaction.......................... -- 480 47,520 --
Conversion of 697 shares of preferred
stock into 4,355 shares of common stock...... (1,045) 44 1,001 --
Conversion of 1,862 shares of preferred
stock into 1,862 shares of common stock.... (2,793) 19 2,774 --
Issuance of 36 shares of common stock
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)
========= ========= ========= ==========
</TABLE>
See Notes to Consolidated Financial Statements.

25
<PAGE>
KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

ORGANIZATION. Kelley Oil & Gas Corporation was incorporated in Delaware
in September 1994 for the purpose of effecting a consolidation (the
"Consolidation") of the equity interests in Kelley Oil Corporation, a Delaware
corporation ("Kelley Oil"), and Kelley Oil & Gas Partners, Ltd., a Texas limited
partnership ("Kelley Partners") of which Kelley Oil was the managing general
partner. The Consolidation was completed on February 7, 1995 upon approval by
investors in Kelley Oil and Kelley Partners. As a result of the Consolidation,
Kelley Oil became a wholly-owned subsidiary of the Company, and Kelley Partners
became a 99.99% owned subsidiary partnership. The Company's operations,
conducted through Kelley Oil and its subsidiaries, include the development,
exploration and acquisition of oil and gas properties and the purchase and sale
of natural gas. In March 1996, Kelley Partners was merged into the Company (the
"Partnership Merger"). Kelley Oil & Gas Corporation, its corporate subsidiaries
and proportionate partnership interests are referred to herein as the "Company."

ACCOUNTING TREATMENT OF THE CONSOLIDATION. At the time of the
Consolidation, the Company's capital stock received by Kelley Oil's stockholders
represented a majority of the total voting power of the combined capital stock
issued by the Company in the Consolidation. Accordingly, the Consolidation was
treated as a purchase by the Company. As a result, the Company's consolidated
financial statements for 1995 reflect Kelley Oil's historical results through
the date of the Consolidation, with results of combined operations recorded
thereafter.

PRINCIPLES OF CONSOLIDATION. The consolidated financial statements
include the accounts of (i) the Company, (ii) its corporate subsidiaries, all of
which are wholly-owned, and (iii) the Company's indirect 100% owned partnership,
Kelley Operating Company, Ltd. ("Kelley Operating"), and (iv) its proportionate
interest in development drilling programs sponsored by Kelley Oil to conduct
drilling operations on properties of Kelley Operating ("1992 DDP" and "1994
DDP") (collectively the "DDPs"). All significant intercompany accounts and
transactions have been eliminated in consolidation.

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 indebtedness
aggregated $14.2 million, $19.2 million and $19.6 million for the years ended
December 31, 1995, 1996 and 1997, respectively.

FINANCIAL INSTRUMENTS. The Company's financial instruments consist of
cash and cash equivalents, receivables, payables and long term debt. As of
December 31, 1997, the estimated fair value of the Company's long term debt was
$304.0 million. The fair value of such financial instruments has been estimated
based on quoted market prices and the Black-Scholes pricing model. The carrying
amount of the Company's other financial instruments approximates fair value.

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. In the fourth quarter of 1995, the
Company implemented the Financial Accounting Standards Board's Statement No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long- Lived
Assets to be Disposed Of" ("SFAS 121"). Under SFAS 121, certain assets are
required to be reviewed periodically

26
<PAGE>
for impairment whenever circumstances indicate their carrying amount exceeds
their fair value and may not be recoverable. As a result of its continuing
operating losses and a decline in its proved reserves at January 1, 1996 from
year-earlier pro forma levels, the Company performed an assessment of the
carrying value of 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 $83.4 million and $66.7 million, respectively, at
December 31, 1995.

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.

HEDGING ACTIVITIES. See Note 9 for a discussion of the Company's
accounting policies related to hedging activities.

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 $1.0 million, $1.8 million
and $2.8 million for the years ended December 31, 1995, 1996 and 1997,
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 loss per
common share before extraordinary item and 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 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, 1995, 1996 and 1997,
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
4.6 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 6.1 million common shares.

STOCK BASED COMPENSATION. In October 1995, the Financial Accounting
Standards Board issued Statement of Financial Accounting Standard No. 123,
"Accounting for Stock Based Compensation" ("SFAS 123"), effective for the
Company on January 1, 1996. SFAS 123 permits, but does not require, a fair value
based method of accounting for employee stock option plans, resulting in
compensation expense being recognized in the results of operations when stock
options are granted. The Company plans to continue the use of its current
intrinsic value based method of accounting for stock option plans where no
compensation expense is recognized.

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

27
<PAGE>
December 15, 1997. Based upon the provisions of SFAS 130, it is anticipated that
the Company will not have a significant change in its reporting requirements.

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 1995 and
1996 have been reclassified to conform to the 1997 presentation.

NOTE 2 - 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 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)

(UNAUDITED)
-----------------------
YEAR ENDED DECEMBER 31,
-----------------------
1996 1997
--------- ---------
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)

28
<PAGE>
NOTE 3 - LONG TERM DEBT

LONG TERM DEBT. The Company's long term debt at December 31, 1996 and 1997 is
comprised of the following:

(IN THOUSANDS)

DECEMBER 31,
--------------------
1996 1997
------- ------
Bank credit facilities...............................$ 13,500 $111,300
13 1/2% Senior Notes ................................ 435 435
10 3/8% Senior Subordinated Notes ................... 119,923 120,615
7 7/8% Convertible Subordinated Notes .............. 27,486 29,710
8 1/2% Convertible Subordinated Debentures ......... 22,909 24,123
-------- --------
184,253 286,183
Less current maturities ........................... -- --
-------- --------
$184,253 $286,183
======== ========

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

The New Credit Facility provides for a maximum $140 million ($125
million prior to amendment) revolving credit loan and matures, with all amounts
owed thereunder becoming due and payable, effective December 1, 2000. Borrowings
under the New Credit Facility are subject to a borrowing base to be determined
semi-annually by the lenders (based in part on the proved oil and gas reserves
and other assets of the Company) which may be redetermined more frequently at
the election of the lenders or the borrowers. At December 31, 1997 the borrowing
base was $138 million. Included in the borrowing base is an overadvance of $23
million. At the time of the next borrowing base determination, which is expected
to be no earlier than May 1, 1998, this overadvance is scheduled to be excluded
from the borrowing base effective June 1, 1998. To the extent that the borrowing
base is less than the aggregate principal amount of all outstanding loans and
letters of credit under the New Credit Facility, 50% of such deficiency must be
cured within 90 days and the balance must be cured within the next 90 days
unless such deficiency is a result of an asset sale, in which case the
deficiency must be cured on the date the borrowing base is re-determined as a
result of such sale. Borrowings under the New Credit Facility are secured by
substantially all of the oil and gas assets of the Company and its subsidiaries,
the proceeds therefrom and the Company's equity interests in the DDPs. In
addition to the borrowings under the New Credit Facility, at December 31, 1997
there were $4.3 million of letters of credit outstanding. The weighted average
interest rate on borrowings outstanding at December 31, 1997 under the New
Credit Facility was 7.76%.

In addition to the $140 million revolving credit loan, at December 31,
1997 the New 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 New Credit
Facility) is continuing, borrowings under the New Credit Facility, as amended,
bear interest, at the option of the borrowers, at either (i) LIBOR plus 1.0% to
1.75% or (ii) the higher of (a) the agent's prime rate plus 0% to 0.25% and (b)
the federal funds rate plus 0.5% to 0.75% (either is dependent on the level of
utilization of the borrowing base). The Borrowers incur a quarterly commitment
fee ranging from 0.30% to 0.50% per annum on the average unused portion of the
borrowing base, depending upon the level of utilization.

29
<PAGE>
The New 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 New 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.

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.

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.

7 7/8% CONVERTIBLE SUBORDINATED NOTES AND 8 1/2% CONVERTIBLE
SUBORDINATED DEBENTURES. The Company has outstanding 7 7/8% Convertible
Subordinated Notes due 1999 (the "7 7/8% Subordinated Notes") in the aggregate
principal amount at maturity of $34.4 million and 8 1/2% Convertible
Subordinated Debentures due April 1, 2000 (the "8 1/2% Subordinated Debentures")
in the aggregate principal amount of $26.9 million (together, the "Subordinated
Debt"). 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.

30
<PAGE>
DEBT MATURITIES. The Company has aggregate debt maturities of $34.8
million in 1999, $138.2 million in 2000 and $125.0 million in 2006.

NOTE 4 - STOCKHOLDERS' EQUITY (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. The Company has not declared the quarterly dividends of $0.65625 per
preferred share for February 1, 1997, May 1, 1997, August 1, 1997, November 1,
1997 and February 1, 1998, aggregating approximately $5.7 million. Future
dividends on the Preferred Stock are restricted 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.

31
<PAGE>
NOTE 5 - 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 which are subject to a four year vesting
period.

Stock option activity for the Company during 1995, 1996 and 1997 was as
follows:
<TABLE>
<CAPTION>
1995 1996 1997
---------------- ---------------- ----------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
OPTIONS IN THOUSANDS OPTIONS PRICE OPTIONS PRICE OPTIONS PRICE
-------- ------- -------- ------- ------- ------
<S> <C> <C> <C> <C> <C>
Stock options outstanding,
beginning of year...................... 564 $ 2.47 2,105 $2.38 4,589 $ 1.63
Granted...............................1,766 2.23 2,520 1.01 482 2.61
Exercised............................. (225) 1.42 (36) 2.38 (415) 1.31
Surrendered or expired................ -- -- -- -- (55) 2.62
----- ----- -----
Stock options outstanding, end of year..2,105 2.38 4,589 1.63 4,601 1.75
===== ===== =====
</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.

At December 31, 1997, options were exercisable for 2.5 million shares at
a weighted average exercise price of $2.11. The range of exercise prices on
outstanding options at December 31, 1997 was $1.00 to $4.13. The remaining
contractual life of these options was approximately 7.9 years. At December 31,
1997, 3.8 million shares were available for future option grants.

The weighted average fair value of options granted during 1995, 1996 and
1997 was $1.30, $0.59 and $1.51, respectively. The fair value of the options
granted was estimated on the date of grant using the Black-Scholes
option-pricing model assuming no expected dividend yield, an expected life of
five years and an expected volatility of 60%. The weighted average risk-free
interest rate was assumed to be 6.8% for options granted in 1995 and 1996, and
6.4% for options granted in 1997.

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 SFAS
123, the Company's net loss and earnings per share for the years ended December
31, 1995, 1996 and 1997 would have been as reflected in the pro forma amounts
indicated below:

<TABLE>
<CAPTION>
1995 1996 1997
--------- --------- --------
<S> <C> <C> <C>
Net income (loss) before extraordinary
item (in thousands.....................................$(211,411) $(14,512) $ 1,319
Loss per common share before extraordinary item.......... (5.31) (.21) (.03)
Net income (loss) (in thousands)......................... (211,411) (31,542) $ 1,319
Loss per common share.................................... (5.31) (.40) (.03)

</TABLE>
32
<PAGE>
ESOP. 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 1997 the Company made matching contributions totaling $0.2
million.

NOTE 6 - INCOME TAXES

The following table sets forth a reconciliation of the statutory federal
income tax for the years ended December 31, 1995, 1996 and 1997:

(IN THOUSANDS)
<TABLE>
<CAPTION>
1995 1996 1997
--------- ------- -------
<S> <C> <C> <C>
Income (loss) before income taxes..............................$(211,291) $(28,965) $ 1,951
--------- -------- -------
Income tax expense (benefit) computed at statutory rates........ (71,839) (9,848) 663
Increase in valuation allowance............................... 71,236 16,322 301
Adjustment to net operating loss carryforward and other....... -- (7,209) (1,459)
Permanent differences:
Nondeductible expenses........................................ 567 735 708
Amortization.................................................. 33 -- --
Other-net..................................................... 3 -- (213)
-------- ------- --------
Tax expense (benefit).......................................$ -- $ -- $ --
======== ======= ========
</TABLE>

No federal income taxes were paid for the years ended December 31, 1995,
1996 and 1997.

The Company's deferred tax position reflects the net tax effects of
temporary differences between the carrying amounts of assets and liabilities for
financial reporting purposes and the amounts used for income tax reporting.
Significant components of the deferred tax liabilities and assets are as
follows:

(IN THOUSANDS)
<TABLE>
<CAPTION>
1995 1996 1997
------- ------- -----
<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........... 53,312 42,696 32,210
Net operating loss carryforwards............................ 35,181 62,179 72,992
Charitable contribution carryforwards....................... 138 78 52
Alternative minimum tax credit carryforwards................ 21 21 21
Valuation allowance.........................................(88,652) (104,974) (105,275)
------- -------- --------
Total deferred tax assets................................... -- -- --
------- ------- -------
Net deferred tax liability....................................$ -- -- $ --
======= ======= =======
</TABLE>

NET OPERATING LOSS CARRYFORWARDS AND ALTERNATIVE MINIMUM TAX CREDITS. As
of December 31, 1997, the Company had cumulative net operating loss
carryforwards ("NOL") for federal income tax purposes of approximately $214.7
million, which expire in 2000 through 2012, and net operating loss carryforwards
for alternative minimum tax

33
<PAGE>
purposes of approximately $175.9 million, which expire in 2008 through 2012. Due
to previous ownership changes, future utilization of the net operating loss
carry forwards will be limited by Internal Revenue Code section 382.

NOTE 7 - 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, 1997, 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, 1997, 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, 1997, the 1992 DDP was indebted to Kelley Oil for loans aggregating
$3.2 million ($0.5 million, net of intercompany eliminations). The Company
recorded interest income on this indebtedness of $0.1 million in 1997, 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 $1.6 million, $0.2 million and $0.1
million in 1995, 1996 and 1997, respectively.

INTEREST ON DDP COMMITMENTS. During 1995, 1996 and 1997, the Company
paid or accrued interest at a market rate in the amounts, net of intercompany
elimination, of $229,000, $91,000 and $11,000, respectively, on deferred
subscription commitments to DDPs.

ADVISORY FEES. During 1996 and 1997, pursuant to an agreement dated
January 23, 1996, the Company paid Bessemer Partners & Co., an affiliate of the
majority stockholder of Contour Production Company L.P., a financial advisory
fee of $2.5 million and $0.5 million, respectively for advisory services. The
Company is obligated to pay an additional advisory fee of $500,000 in 1998.

NOTE 8 - 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 1997, natural gas sales to two purchasers accounted for
approximately 90% 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 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

34
<PAGE>
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 each of 1995 and 1996, the Company incurred
restructuring expenses of $1.1 million and $4.3 million, respectively,
associated primarily with staff reductions, related severance settlements and
reorganization costs. Accrued expenses on the balance sheet include $3.5 million
and $0.9 million at December 31, 1996 and 1997, 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, 1995, 1996 and 1997 were $1.9 million, $1.3 million and
$0.8 million, respectively. For the balance of the lease terms, minimum rentals
are as follows:

(IN THOUSANDS)

1998.......................................................$ 545
1999....................................................... 517
2000....................................................... 517
2001....................................................... 255
------
Total......................................................$1,834
======

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 9 - 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 1997, 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.

35
<PAGE>
transaction and transportation costs. In addition, as of December 31, 1997, the
Company has outstanding natural gas basis swap agreements covering approximately
34% of its anticipated natural gas production for January 1998 through September
1998. Hedging activities decreased revenues by approximately $4.2 million in
1997 as compared to estimated revenues had no hedging activities been conducted.
At December 31, 1997, the unrealized gain on the Company's existing hedging
instruments for future production months in 1998 approximated $1.4 million.

NOTE 10 - SUPPLEMENTARY FINANCIAL AND OPERATING INFORMATION ON OIL AND GAS
EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)

This footnote provides unaudited information required by Statement of
Financial Accounting Standards No. 69, "Disclosures about Oil and Gas Producing
Activities."

CAPITALIZED COSTS. Capitalized costs and accumulated depreciation,
depletion and amortization relating to the Company's oil and gas producing
activities, all of which are conducted within the continental United States, are
summarized below.

(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------
1995 1996 1997
--------- --------- ---------
<S> <C> <C> <C>
Unevaluated properties.......... ...........................$ 13,050 $ 12,521 $ 49,854
Properties subject to amortization.......................... 287,970 338,794 463,263
--------- ---------- ---------
Capitalized costs........................................... 301,020 351,315 513,117
Accumulated depreciation, depletion and amortization........ (173,996) (194,367) (221,729)
--------- ---------- ---------
Net capitalized costs.......................................$ 127,024 $ 156,948 $ 291,388
========= ========== =========
</TABLE>
COSTS INCURRED. Costs incurred in oil and gas property acquisition,
exploration and development activities are summarized below.

(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------
1995 1996 1997
--------- --------- ---------
<S> <C> <C> <C>
Property acquisition costs:(1)
Proved....................................................$ 126,577 $ 11,594 $ 73,190
Unproved (2).............................................. 88,539 2,160 40,997
Exploration costs........................................... 9,521 5,438 9,525
Development costs........................................... 31,730 41,790 40,713
--------- --------- ---------
Total costs incurred......................................$ 256,367 $ 60,982 $ 164,425
========= ========= =========
</TABLE>
- ------------
(1) - Includes assets acquired in the Consolidation aggregating $207 million
for the year ended December 31, 1995.

(2) - Includes $40 million in unproved assets acquired from SPR on
December 1, 1997.

RESERVES. The following table summarizes the Company's net ownership
interests in estimated quantities of proved oil and gas reserves and changes in
net proved reserves, all of which are located in the continental United States,
for the years ended December 31, 1995, 1996 and 1997. Reserves estimates
contained below were prepared by H.J. Gruy & Associates,

36
<PAGE>
Inc. ("Gruy"), independent petroleum engineers. See "Estimated Proved Reserves--
Uncertainties in Estimating Reserves and Future Net Cash Flows" under Items 1
and 2 of this Report.
<TABLE>
<CAPTION>
CRUDE OIL, CONDENSATE
AND NATURAL GAS LIQUIDS NATURAL GAS
(MBBLS) (MMCF)
----------------------------- ---------------------------
1995 1996 1997 1995 1996 1997
------- ------- ------- ------- ------- -----
<S> <C> <C> <C> <C> <C> <C>
Proved developed and undeveloped reserves:
Beginning of year............ 1,236 1,387 1,466 93,612 196,273 297,634
Revisions of previous
estimates................... (1,324) (89) 106 (64,027) (30,519) 21,831
Purchases of reserves
in place.................... 1,756 57 1,351 127,962 30,844 51,712
Extensions and discoveries... 156 477 256 66,864 128,692 13,892
Sale of reserves in place.... (118) (134) -- (10,388) (4,190) --
Production................... (319) (232) (226) (17,750) (23,466) (30,202)
------- ------- ------- ------- ------- -------
End of year.................. 1,387 1,466 2,953 196,273 297,634 354,867
======= ======= ======= ======= ======= =======
Proved developed reserves
at end of year............... 1,197 977 2,432 111,287 173,465 257,800
======= ======= ======= ======= ======= =======
</TABLE>

STANDARDIZED MEASURE. The following table of the Standardized Measure of
Discounted Future Net Cash Flows concerning the standardized measure of future
cash flows from proved oil and gas reserves are presented in accordance with
Statement of Financial Accounting Standards No. 69. As prescribed by this
statement, the amounts shown are based on prices and costs at the end of each
period, and assume continuation of existing economic conditions. Future income
taxes are based on year-end statutory rates, adjusted for operating loss
carryforwards and tax credits. A discount factor of 10% was used to reflect the
timing of future net cash flow. Extensive judgments are involved in estimating
the timing of production and the costs that will be incurred throughout the
remaining lives of the fields. Accordingly, the estimates of future net revenues
from proved reserves and the present value thereof may not be materially correct
when judged against actual subsequent results. Further, since prices and costs
do not remain static, and no price or cost changes have been considered, and
future production and development costs are estimates to be incurred in
developing and producing the estimated proved oil and gas reserves, the results
are not necessarily indicative of the fair market value of estimated proved
reserves, and the results may not be comparable to estimates disclosed by other
oil and gas producers.

(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------
1995 1996 1997
--------- --------- ---------
<S> <C> <C> <C>
Future cash inflows......................................... $ 431,351 $1,099,089 $ 930,357
Future production costs..................................... (76,021) (113,178) (196,048)
Future development costs.................................... (36,524) (81,932) (106,123)
Future income tax expenses.................................. (8,577) (162,887) (37,050)
--------- ---------- ---------
Future net cash flows..................................... 310,229 741,092 591,136
10% annual discount for estimating timing of cash flows..... (139,177) (307,321) (227,249)
--------- ---------- ---------
Standardized measure of discounted future net cash flows.. $ 171,052 $ 433,771 $ 363,887
========= ========== =========
</TABLE>
The standardized measure of discounted future net cash flows as of
December 31, 1995, 1996 and 1997 was calculated using prices in effect as of
those dates, which averaged $19.73, $25.18 and $16.93, respectively, per barrel
of oil and $2.06, $3.66 and $2.49, respectively, per Mcf of natural gas.

37
<PAGE>
CHANGE IN STANDARDIZED MEASURE. Changes in standardized measure of
future net cash flows relating to proved oil and gas reserves are summarized
below.

(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------
1995 1996 1997
-------- --------- --------
<S> <C> <C> <C>
Changes due to current year operations:
Sales of oil and gas, net of production costs.............. $(25,207) $ (48,307) $(62,080)
Sale of reserves in place.................................. (5,884) (6,836) --
Extensions and discoveries................................. 62,407 192,174 21,945
Purchases of reserves in place............................. 90,660 11,594 91,034
Future development costs incurred.......................... 10,216 24,500 21,806
Changes due to revisions in standardized variables:
Prices and production costs................................ 21,055 159,292 (243,851)
Revisions of previous quantity estimates................... (22,223) (50,594) 25,345
Revisions of purchased oil and gas properties.............. (28,199) -- --
Estimated future development costs......................... 17,676 3,254 (17,413)
Income taxes............................................... (893) (82,831) 69,489
Accretion of discount...................................... 7,145 17,575 51,818
Production rates (timing) and other........................ (26,541) 42,898 (27,977)
-------- --------- --------
Net increase (decrease).................................. 100,212 262,719 (69,884)
Beginning of year.......................................... 70,840 171,052 433,771
-------- --------- --------
End of year.............................................. $171,052 $ 433,771 $363,887
======== ========= ========
</TABLE>
Sales of oil and gas, net of production costs, are based on historical
pre-tax results. Extensions and discoveries, purchases of reserves in place and
the changes due to revisions in standardized variables are reported on a pre-tax
discounted basis, while the accretion of discount is presented after tax.
Extensions and discoveries include proved undeveloped reserves attributable to
Kelley Oil's interests in drill sites assigned to DDPs but do not give effect to
the Consolidation prior to 1995.

PART III

ITEMS 10, 11, 12 AND 13. EXECUTIVE OFFICERS OF THE COMPANY; EXECUTIVE
COMPENSATION; SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT;
AND CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, RESPECTIVELY.

The information called for by these Items is incorporated by reference
to the Company's definitive Proxy Statement to be filed by the Company pursuant
to Regulation 14A of the General Rules and Regulations under the Securities and
Exchange Act not later than April 30, 1998.

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(a) FINANCIAL STATEMENTS AND SCHEDULES:

(1) FINANCIAL STATEMENTS: The financial statements required to be filed
are included under Item 8 of this Report.

38
<PAGE>
(2) SCHEDULES: All schedules for which provision is made in applicable
accounting regulations of the SEC have been omitted as the schedules are either
not required under the related instructions, are not applicable or the
information required thereby is set forth in the Company's Consolidated
Financial Statements or the Notes thereto.

(3) EXHIBITS:

EXHIBIT

NUMBER: EXHIBIT

2.1 Agreement and Plan of Consolidation among the Registrant,
Kelley Oil Corporation, Kelley Oil & Gas Partners, Ltd.
("Kelley Partners") and the other parties named therein
(incorporated by reference to Exhibit 2.1 to the Registrant's
Registration Statement (the "Consolidation Registration
Statement") on Form S-4 (Reg No. 33-84338) filed September 26,
1994, as amended).

3.1 Certificate of Incorporation of the Registrant (incorporated
by reference to Exhibit 3.1 to the Consolidation Registration
Statement).

3.2 Certificate of Amendment to Certificate of Incorporation of
the Registrant dated December 20, 1994 (incorporated by
reference to Exhibit 3.2 to the Consolidation Registration
Statement).

3.3 Certificate of Correction to Certificate of Incorporation of
the Registrant dated February 12, 1996 (incorporated by
reference to Exhibit 3.1 to the Registrant's Current Report on
Form 8-K (File No. 0-25214) dated February 15, 1996).

3.4 Certificate of Designation of $2.625 Convertible Exchangeable
Preferred Stock of the Registrant (incorporated by reference
to Exhibit 3.1 to the Registrant's Current Report on Form 8-K
(File No. 0-25214) dated February 10, 1995).

3.5 Certificate of Designations of Cumulative Convertible
Preferred Stock of the Registrant (incorporated by reference
to Exhibit 3.2 to the Registrant's Current Report on Form 8-K
(File No. 0-25214) dated February 10, 1995).

3.6 Certificate of Merger of Kelley Oil & Gas Partners, Ltd. into
Kelley Oil & Gas Corporation dated March 28, 1996.

3.7 Certificate of Amendment to Certificate of Incorporation of
the Registrant dated April 29, 1996.

3.8 Bylaws of the Registrant (incorporated by reference to Exhibit
3.5 to the Consolidation Registration Statement).

4.1 Certificate representing Common Stock of the Registrant
(incorporated by reference to Exhibit 4.1 to the Consolidation
Registration Statement).

4.2 Certificate representing $2.625 Convertible Exchangeable
Preferred Stock of the Registrant (incorporated by reference
to Exhibit 4.2 to the Consolidation Registration Statement).

4.3 Supplemental Indenture dated February 7, 1995 among the
Registrant, Kelley Partners and United States Trust Company of
New York, relating to Kelley Partners' 8 1/2% Convertible
Subordinated Debentures (the "8 1/2% Debentures") due 2000
(incorporated by reference to Exhibit 4.1 to the Registrant's
Current Report on Form 8-K (File No. 0-25214) dated February
10, 1995).

4.4 Supplemental Indenture dated March 29, 1996 between the
Registrant and the United States Trust Company of New York,
relating to the 8 1/2% Debentures (incorporated by reference
to Exhibit 4.4 to the Registrant's Annual Report on Form 10-K
(File No. 0-25214) for the year ended December 31, 1995).

39
<PAGE>
4.5 Supplemental Indenture dated February 7, 1995 among the
Registrant, Kelley Partners and United States Trust Company of
New York, relating to Kelley Partners' 7 7/8% Convertible
Subordinated Notes (the "7 7/8% Notes") due 1999 (incorporated
by reference to Exhibit 4.2 to the Registrant's Current Report
on Form 8-K (File No. 0-25214) dated February 10, 1995).

4.6 Supplemental Indenture dated March 29, 1996 between the
Registrant and the United States Trust Company of New York,
relating to the 7 7/8% Notes (incorporated by reference to
Exhibit 4.6 to the Registrant's Annual Report on Form 10-K
(File No. 0-25214) for the year ended December 31, 1995).

4.7 Indenture dated as of June 15, 1995 among the Registrant, as
issuer, Kelley Partners, Kelley Operating Company, Ltd. and
Kelley Oil Corporation, as guarantors, and Chemical Bank, as
trustee, relating to the Registrant's 13 1/2% Senior Notes due
1999 (incorporated by reference to Exhibit 4.5 to the
Registrant's Registration Statement on Form S-3 (Reg. No.
33-92214) dated June 9, 1995.

4.8 Supplemental Indenture dated as of October 28, 1996, among the
Registrant, as issuer, Kelley Operating Company, Ltd. and
Kelley Oil Corporation, as guarantors, and The Chase Manhattan
Bank (formerly Chemical Bank), as trustee, relating to the
Registrant's 13 1/2% Senior Notes due 1999 (incorporated by
reference to Exhibit 4.3 to the Registrant's Quarterly Report
on Form 10-Q (File No. 0-25214) for the quarterly period ended
September 20, 1996).

4.9 Indenture dated as of October 15, 1996, among the Registrant,
as issuer, Kelley Oil Corporation and Kelley Operating
Company, Ltd., as guarantors, and United States Trust Company
of New York, relating to the Registrant's 10 3/8% Senior
Subordinated Notes due 2006 (incorporated by reference to
Exhibit 4.1 to the Registrant's Quarterly Report on Form 10-Q
(File No. 0-25214) for the quarterly period ended September
30, 1996).

4.10 Form of the Registrant's 10 3/8% Senior Subordinated Note Due
2006, Series B (incorporated by reference to Exhibit 4.5 to
the Registrant's Registration Statement on Form S-4 (Reg.
No. 333-18481) filed December 20, 1996, as amended).

4.11 Option Agreement dated as of February 15, 1996 between the
Registrant and Contour Production Company L.L.C. (incorporated
by reference to Exhibit 4.1 to the Registrant's Current Report
on Form 8-K (File No. 0-25214) dated February 15, 1996).

10.1 Amended and Restated Employee Stock Ownership Plan of Kelley
Oil effective as of January 1, 1989 (incorporated by reference
to Exhibit 10.15 to Kelley Oil's Annual Report on Form 10-K
(File No. 0-17585) for the year ended December 31, 1991).

10.2 1987 Incentive Stock Option Plan (the "1987 Plan") of Kelley
Oil (incorporated by reference to Kelley Oil's Annual Report
on Form 10-K (File No. 0-17585) for the year ended December
31, 1988).

10.3 1991 Incentive Stock Option Plan (the "1991 Plan") of Kelley
Oil (incorporated by reference to Exhibit 10.3 to Kelley Oil's
Annual Report on Form 10-K (File No. 0-175850 for the year
ended December 31, 1991).

10.4 1995 Incentive Stock Option Plan of the Registrant (the "1995
Plan") (incorporated by reference to Exhibit 10.4 to the
Registrant's Annual Report on Form 10-K (File No. 0-25214) for
the year ended December 31, 1995).

10.5 Amendment to the 1987 Plan, 1991 Plan and 1995 Plan
(incorporated by reference to Exhibit 10.5 to the Registrant's
Current Report on Form 8-K (File No. 0-25214) dated February
15, 1996).

10.6 1996 Nonqualified Stock Option Plan of the Registrant
(incorporated by reference to Exhibit 10.4 to the Registrant's
Current Report on Form 8-K (File No. 0-25214) dated February
15, 1996).

40
<PAGE>
10.7 Employment Agreement dated as of February 15, 1996 between the
Registrant and John F. Bookout, Jr. (incorporated by reference
to Exhibit 10.2 to the Registrant's Current Report on Form 8-K
(File No. 0-25214) dated February 15, 1996).

10.8 Form of Employment Agreements dated as of February 15, 1996
between the Registrant and each of Dallas Laumbach and William
Albrecht (incorporated by reference to Exhibit 10.3 to the
Registrant's Current Report on Form 8-K (File No. 0-25214)
dated February 15, 1996).

10.9 Employment Agreement dated as of March 20, 1997 with David C.
Baggett (incorporated by reference to Exhibit 10.9 to the
Registrant's Annual Report on Form 10-K (File No. 0-25214) for
the year ended December 31, 1996).

10.10 Amended and Restated Credit Agreement among Kelley Oil & Gas
Corporation, Kelley Oil Corporation and Kelley Operating
Company, Ltd., as Borrowers, Concorde Gas Marketing, Inc.,
Kelley Partners 1992 Development Drilling Joint Venture,
Kelley Partners 1994 Development Drilling Joint Venture,
Kelley Partners 1992 Development Drilling Program and Kelley
Partners 1994 Development Drilling Program, as Guarantors,
Texas Commerce Bank National Association, as Agent, Chase
Securities Inc., as Arranger and Syndication Agent, and the
Lenders Signatory thereto, dated as of December 12, 1996
(incorporated by reference to Exhibit 4.3 to the Registrant's
Registration Statement on Form S-4 (Reg. No. 333-18481) filed
December 20, 1996, as amended).

10.11 1996 Incentive Stock Option Plan of the Registrant
(incorporated by reference to Exhibit 10.11 to the
Registrant's Annual Report on Form 10-K (File No. 0-25214) for
the year ended December 31, 1996).

10.12 1997 Annual and Long-Term Incentive-Performance Plan of the
Registrant.

10.13 Purchase and Sale Agreement, dated October 21, 1997, between
the Company and SCANA Petroleum Resources, Inc. (incorporated
by reference to Exhibit 10.2 to the Registrant's Current
Report on Form 8-K (File No. 0-25214) dated December 1, 1997).

10.14 Amended and Restated Credit Agreement dated December 1, 1997
among the Company, Kelley Oil Corporation and Kelley Operating
Company, Ltd., as Borrowers; Concorde Gas Marketing, Inc.,
Kelley Partners 1992 Development Drilling Joint Venture,
Kelley Partners 1994 Development Drilling Joint Venture,
Kelley Partners 1992 Development Drilling Program, and Kelley
Partners 1994 Development Drilling Program, as Guarantors;
Texas Commerce Bank National Association, as Agent; Chase
Securities Inc., as Arranger and Syndication Agent; and
certain other lenders signatory thereto (incorporated by
reference to Exhibit 10.3 to the Registrant's Current Report
on Form 8-K (File No. 0-25214) dated December 1, 1997).

21.1 Subsidiaries of the Registrant (incorporated by reference to
Exhibit 21.1 to the Registrant's Annual Report on Form 10-K
(File No. 0-25214) for the year ended December 31, 1996).

23.1 Consent of Deloitte & Touche LLP.

23.2 Consent of H.J. Gruy & Associates, Inc.

27 Financial Data Schedule (included only in the electronic
filing of this document).

(b) REPORTS ON FORM 8-K:

The Company filed a Current Report on Form 8-K dated October 21, 1997 and a
Current Report on Form 8-K dated December 1, 1997, filed on December 16,
1997 and amended on February 17, 1998 and March 30, 1998.

41
<PAGE>
SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, this 27th day of
March, 1998.

KELLEY OIL & GAS CORPORATION

By:/s/ JOHN F. BOOKOUT By:/s/ DAVID C. BAGGETT By: /s/ KENNETH R. BICKETT
John F. Bookout David C. Baggett Kenneth R. Bickett
Chief Executive Officer Senior Vice President Controller
and Chief Financial Officer (Chief Accounting Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed as of the 27th day of March, 1998 by the following
persons in their capacity as directors of the Registrant.

/s/ JOHN F. BOOKOUT /s/ WILLIAM J. MURRAY
John F. Bookout William J. Murray

/s/ JOHN J. CONKLIN, JR. /s/ OGDEN M. PHIPPS
John J. Conklin, Jr. Ogden M. Phipps

/s/ RALPH P. DAVIDSON /s/ MICHAEL B. ROTHFELD
Ralph P. Davidson Michael B. Rothfeld

/s/ WARD W. WOODS
Ward W. Woods

Exhibit 3.6

CERTIFICATE OF MERGER
OF
KELLEY OIL & GAS PARTNERS, LTD.
INTO
KELLEY OIL & GAS CORPORATION

Pursuant to the provisions of Section 263(c) of the Delaware General
Corporation Law (the "DELAWARE GCL"), the undersigned corporation submits the
following Certificate of Merger for the purpose of effecting a merger of a
domestic corporation with a limited partnership of another state under the
Delaware GCL.

1. The name and state of incorporation or organization of each of the
constituent entities are:

NAME OF STATE OF INCORPORATION
ENTITY OR ORGANIZATION

Kelley Oil & Gas Corporation Delaware
Kelley Oil & Gas Partners, Ltd. Texas

2. An Agreement and Plan of Merger (the "MERGER AGREEMENT") providing
for the merger of Kelley Oil & Gas Partners, Ltd. with and into Kelley Oil & Gas
Corporation (the "MERGER") has been approved, adopted, certified, executed and
acknowledged by each of the constituent entities in accordance with Section
263(c) of the Delaware General Corporation Law and the partnership agreements
and laws of the state of organization of the constituent limited partnerships.

3. The surviving corporation in the Merger is Kelley Oil & Gas
Corporation.

4. The certificate of incorporation of the surviving corporation shall
be the certificate of incorporation of Kelley Oil & Gas Corporation.

5. The executed Merger Agreement is on file at the principal place of
business of Kelley Oil & Gas Corporation at 601 Jefferson, Houston, Texas 77002,
and a copy of the Merger Agreement will be furnished by the surviving
corporation, on request and without cost, to any stockholder of the surviving
corporation and any former partner of the constituent limited partnerships.

IN WITNESS WHEREOF, Kelley Oil & Gas Corporation has caused this
certificate to be signed as of this 28th day of March, 1996.

KELLEY OIL & GAS CORPORATION

ATTEST: By:/s/ WILLIAM C. RANKIN
William C. Rankin
Senior Vice President and
Chief Financial Officer

/s/ SHIRLEY W. SMITH
Shirley W. Smith,
Secretary

Exhibit 3.7

CERTIFICATE OF AMENDMENT OF
CERTIFICATE OF INCORPORATION
OF
KELLEY OIL & GAS CORPORATION

--------------------

Pursuant to Section 242 of the General Corporation Law
of the State of Delaware

--------------------

Kelley Oil & Gas Corporation, a corporation organized and existing under
the General Corporation Law of the State of Delaware (the "Corporation"), does
hereby certify as follows:

1. The original Certificate of Incorporation of the Corporation was
filed in the office of the Secretary of State of the State of Delaware on
September 20, 1994, and a Certificate of Amendment thereto was filed in the
office of the Secretary of State of the State of Delaware on December 20, 1994.

2. At a meeting of the Board of Directors of the Corporation,
resolutions were duly adopted setting forth a proposed amendment to the
Certificate of Incorporation of the Corporation, declaring the amendment to be
advisable and directing that it be submitted to the stockholders of the
Corporation for consideration. The resolution setting forth the proposed
amendment is as follows:

RESOLVED that the Certificate of Incorporation of the Corporation be
amended by (I) deleting the word "not" from the third line of Article 7 and (ii)
changing the first paragraph of Article 4 thereof to be and read in its entirely
as follows:

"4. NUMBER AND DESIGNATION OF SHARES. The total number of shares
of capital stock that the Corporation shall have the authority to issue
is Two-Hundred-Twenty Million (220,000,000) shares, which shall be
divided into two classes as follows: Two-Hundred Million (200,000,000)
shares of Common Stock, $.01 par value ("Common Stock"), and Twenty
Million (20,000,000) shares of Preferred Stock, $1.50 par value
("Preferred Stock"). The powers, designations, preferences, rights and
qualifications, limitations or restrictions of the Common Stock and the
Preferred Stock are set forth below."

3. The holders of the Corporation's capital stock representing more than
50% of the outstanding Common Stock of the Corporation and more than 50% of the
total voting power of the Corporation consented in writing to the adoption of
the foregoing amendment in accordance with the provisions of Section 228 of the
General Corporation Law of the State of Delaware. A written notice of the action
of the stockholders by written consent shall be given in accordance with Section
228(d) of the General Corporation Law of the State of Delaware.

4. The foregoing amendment was duly adopted in accordance with the
provisions of Sections 242 and 228 of the General Corporation Law of the State
of Delaware.

IN WITNESS WHEREOF, Kelley Oil & Gas Corporation has caused this
Certificate to be signed by its Senior Vice President as of this 29th day of
April, 1996.

/s/ WILLIAM C. RANKIN
William C. Rankin
Senior Vice President

Exhibit 10.12

KELLEY OIL AND GAS CORPORATION
1997 ANNUAL AND LONG-TERM INCENTIVE-PERFORMANCE PLAN

1. PURPOSE OF THE PLAN

The purpose of the 1997 Annual and Long-Term Incentive-Performance Plan
(the "1997 Plan") of Kelley Oil and Gas Corporation (the "Company") and its
Subsidiaries is to provide an incentive to attract and retain key employees, by
encouraging and rewarding high levels and superior quality of performance,
thereby strengthening and promoting the growth and general prosperity of the
Company and its Subsidiaries, and benefiting the shareholders. Awards granted
under the Plan may be (a) annual performance awards ("Annual Performance
Awards"); (b) stock options ("Options") which may be designated as (i)
nonqualified stock options ("NQSOs") not intended to qualify as incentive stock
options ("ISOs") under Section 422 of the Internal Revenue Code of 1986, as
amended (the "Code"), or (ii) ISO's; or (c) other forms of stock-based
performance awards, as hereinafter defined (collectively, the "Awards"). For
purposes of the Plan, "Subsidiary" means any corporation in an unbroken chain of
corporations beginning with the Company if, at the time of the granting of the
Award, each of the corporations other than the last corporation in the unbroken
chain owns stock possessing 50% or more of the total combined voting power of
all classes of stock in one of the other corporations in the chain, and
Subsidiaries means more than one of any such corporations.

2. SHARES OF STOCK SUBJECT TO THE PLAN

The Awards may be granted with respect to shares of Common Stock, $0.01
par value, of the Company (the "Common Stock"). Shares delivered upon exercise
of the Awards, at the election of the Board of Directors of the Company, may be
Common Stock that is authorized but previously unissued or stock reacquired by
the Company or both. Subject to the provisions of Section 14, the maximum number
of shares of Common Stock with respect to which the Awards may be granted under
the Plan shall not exceed 4,200,000 shares of Common Stock. Any shares subject
to an Award under the Plan, which Award for any reason expires or is terminated
unexercised as to such shares, shall again be available for the grant of other
Awards under the Plan; provided, however, that forfeited Common Stock or other
securities shall not be available for further Awards if the participant has
realized any benefits of ownership from such Common Stock.

3. ADMINISTRATION

The Plan shall be administered by the Company's Compensation Committee
(the "Committee") composed of not less than two members of the Board of
Directors of the Company, each of whom shall be ineligible to participate in the
Plan. Subject to the provisions of the Plan, the Committee shall have full
discretion and the exclusive power to (i) select the employees who will
participate in the Plan and to make Awards to such employees, (ii) determine the
time at which such Awards shall be granted and any terms and conditions with
respect to such Awards as shall not be inconsistent with the provisions of the
Plan, and (iii) resolve all questions relating to the administration of the
Plan.

The interpretation of and application by the Committee of any provision
of the Plan, when performed in good faith and in its sole judgment, shall be
final and conclusive. The Committee, in its sole discretion, may establish such
rules and guidelines relating to the Plan as it may deem desirable.

The Committee may employ such legal counsel, consultants and agents as
it may deem desirable for the administration of the Plan and may rely upon any
opinion received from any such counsel or consultant and any computation
received from any such consultant or agent. The Committee shall keep minutes of
its actions under the Plan.

No member of the Board of Directors or the Committee shall be liable
for any action or determination made in good faith and in a manner which he
reasonably believed to be in or not opposed to the best interests of the Company
with respect to the Plan or any Awards granted thereunder.

A-1
<PAGE>
With respect to administration of this Plan, the Company shall
indemnify each present and future member of the Committee and the Board of
Directors against, and each member of the Committee and the Board of Directors
shall be entitled without further act on his part to indemnity from the Company
for, all expenses (including without limitation attorneys' fees, the amount of
judgments and the amount of approved settlements made with a view to the
curtailment of costs of litigation, other than amounts paid to the Company
itself) reasonably incurred by him in connection with or arising out of any
action, suit or proceeding in which he may be involved by reason of his being or
having been a member of the Committee and/or the Board of Directors, whether or
not he continues to be a member of the Committee and/or the Board of Directors
at the time of incurring the expenses unless he has been found not to meet the
standard set forth in the preceding paragraph. Also, this indemnity shall not
include any expenses incurred by any member of the Committee and/or the Board of
Directors in respect of matters as to which he shall be finally adjudged in any
action, suit or proceeding to have been guilty of gross negligence or willful
misconduct in the performance of his duty as a member of the Committee and the
Board of Directors. In addition, no right of indemnification under this Plan
shall be available to or enforceable by any member of the Committee and Board of
Directors unless, within 60 days after institution of any action, suit or
proceeding, he shall have offered the Company, in writing, the opportunity to
handle and defend same at its own expense. This right of indemnification shall
inure to the benefit of the heirs, executors or administrators of each member of
the Committee and the Board of Directors and shall be in addition to all other
rights to which a member of the Committee and the Board of Directors may be
entitled as a matter of law, contract, or otherwise.

4. ELIGIBILITY

The individuals who shall be eligible to participate in the Plan shall
be officers and such other key employees of the Company as the Committee may
from time to time determine ("Eligible Employees"). Directors of the Company who
are not excluded from participation under Section 3 shall be eligible to
participate in the Plan. An employee or non-employee director who has been
granted an Award in one year shall not necessarily be entitled to be granted
Awards in subsequent years.

5. STOCK OPTIONS

The Committee may grant Options, as provided herein, which shall be
evidenced by a stock option agreement and may be designated as (i) NQSOs or (ii)
ISOs intended to qualify under Code Section 422. The maximum number of shares
subject to Options which may be issued or transferred to any employee under this
Plan each year is 250,000 shares.

(a) NQSOs.

(i) A NQSO is a right to purchase a specified number of shares of
Common Stock during such time as the Committee may determine, not to exceed ten
years, at a price determined by the Committee that, unless provided otherwise by
the Committee, is not less than the fair market value of the Common Stock on the
date the option is granted.

(ii) The purchase price of the Common Stock subject to the NQSO may be
paid in cash. At the discretion of the Committee, the purchase price may also be
paid by the tender of Common Stock or through a combination of Common Stock and
cash or through such other means as the Committee determines are consistent with
the Plan's purpose and applicable law. No fractional shares of Common Stock will
be issued or accepted.

(iii) Without limiting the foregoing, to the extent permitted by law
(including relevant state law), (A) the Committee may agree to accept, as full
or partial payment of the purchase price of Common Stock issued upon the
exercise of the NQSO, a promissory note of the person exercising the NQSO
evidencing the person's obligation to make future cash payments to the Company,
which promissory note shall be payable as determined by the Company (but in no
event later than five years after the date thereof), shall be secured by a
pledge of the shares of Common Stock purchased and shall bear interest at a rate
established by the Committee and (B) the Committee may permit the person
exercising the NQSO, either on a selective or aggregate basis, to simultaneously
exercise the NQSO and sell the shares of Common Stock acquired, pursuant to a
brokerage or similar arrangement approved in advance by the Committee, and use
the proceeds from sale as payment of the purchase price of such Common Stock.

A-2
<PAGE>
(b) ISOs.

(i) An ISO is an Award in the form of an Option to purchase Common
Stock that complies with the requirements of Code Section 422 or any successor
section.

(ii) The aggregate fair market value (determined at the time of the
grant of the Award) of the shares of Common Stock subject to ISOs which are
exercisable by one person for the first time during a particular calendar year
shall not exceed $100,000, determined as of the date of grant. To the extent
that ISOs granted to an employee exceed the limitation set forth in the
preceding sentence, ISOs granted last shall be treated as NQSOs.

(iii) No ISO may be exercisable more than:

(A) in the case of an employee who does not own more than 10%
of the combined voting power of all classes of stock of the Company and its
Subsidiaries (a "Ten Percent Shareholder"), on the date the ISO is granted, ten
years after the date the ISO is granted; and

(B) in the case of an employee who is a Ten Percent
Shareholder, within the meaning of Code Section 422, on the date the ISO is
granted, five years after the date the ISO is granted.

(iv) The exercise price of any ISO shall be determined by the Committee
and shall be no less than:

(A) in the case of an employee who is not a Ten Percent
Shareholder on the date the ISO is granted, the fair market value of the Common
Stock subject to the ISO on such date; and

(B) in the case of an employee who is a Ten Percent
Shareholder on the date the ISO is granted, not less than 110 percent of the
fair market value of the Common Stock subject to the ISO on such date.

(v) The Committee may provide that the option price under an ISO may be
paid by one or more of the methods available for paying the option price of an
NQSO.

6. ANNUAL INCENTIVE-PERFORMANCE AWARDS

Annual Incentive-Performance Awards ("Annual Awards") granted under the
Plan (i) may be denominated or payable in cash, Common Stock (including without
limitation, Restricted Stock), other securities or other awards and (ii) shall
confer on the holder thereof the right to receive payments, in whole or in part,
upon the achievement of such performance goals during such performance periods
as the Committee shall establish. Subject to the terms of the Plan and any
applicable Annual Award, the Performance Goals (as defined below) and
Performance Criteria (as defined below) to be achieved during any specified
period, the length of any specified period, the amount of any Annual Award
granted and the amount of any payment or transfer to be made pursuant to any
Annual Award shall be determined by the Committee.

The designation of Eligible Employees shall be made by the Committee in
its sole discretion in writing in a timely manner. The Committee also has sole
discretion (i) to establish criteria to measure performance ("Performance
Criteria") and set annual performance objectives ("Performance Goals") with
respect to such Performance Criteria for the Company, units within the Company,
and individual performances, weighting of the Performance Goals and Performance
Criteria, payments with respect to the Performance Goals and Performance
Criteria, including specific forms of payment (cash or cash and restricted
shares) and the terms of the restricted shares. The Committee further has the
sole discretion to establish, as to each Annual Award, the number of shares to
be issued and/or the maximum amount of the cash payment to a designated
participant if all of the Performance Goals and Performance Criteria are met;
provided the maximum number of shares which may be issued to any one participant
per year under this Section 6 is 150,000 shares of Common Stock, and the maximum
cash payment to any one participant per year under this Section 6 is $300,000.

The Committee must certify in writing that the applicable performance
goals have been met prior to issuance of any certificates for shares of Common
Stock or payment of cash with respect to Annual Awards. Upon certification by
the

A-3
<PAGE>
Committee, the certificates may be issued or transferred and/or any cash
payments made, subject to other applicable provisions of the Plan, including but
not limited to, all legal requirements and applicable tax withholding.

7. RESTRICTED STOCK

Restricted Stock is Common Stock of the Company ("Restricted Stock")
that may be issued or transferred by the Committee to a participant at a price
determined by the Committee, which price may be zero, and is subject to
restrictions on transfer and/or such other restrictions on incidents of
ownership as the Committee may determine.

8. OTHER STOCK-BASED INCENTIVE AWARDS

The Committee may from time to time grant Awards under this Plan that
provide the participant with the right to purchase Common Stock or that are
valued by reference to the fair market value of the Common Stock (including, but
not limited to, phantom securities or dividend equivalents). Such Awards shall
be in a form determined by the Committee (and may include terms contingent upon
a change of control of the Company); PROVIDED that such Awards shall not be
inconsistent with the terms and purposes of the Plan. The Committee will
determine the price of any Award and may accept any lawful consideration.

9. EXERCISE OF OPTIONS

The Committee may provide for the exercise of Options in installments
and upon such terms, conditions and restrictions as it may determine. The
Committee may provide for termination of an Option in the case of termination of
employment or any other reason.

An Option granted hereunder shall be exercisable, in whole or in part,
only by written notice delivered in person or by mail to the Secretary of the
Company at its principal office, specifying the number of shares of Common Stock
to be purchased and accompanied by payment thereof and otherwise in accordance
with this Plan and the stock option agreement pursuant to which the Option was
granted.

For purposes of this Plan, the fair market value of a share of the
Common Stock shall be (i) if the Common Stock is traded on an established
securities market, the closing price of such Common Stock for the day before the
Option is granted and (ii) if the Common Stock is not so traded, an amount
determined by the Committee in good faith and based on such factors as it deems
relevant to such determination.

10. RIGHTS IN EVENT OF DEATH OR DISABILITY

If an optionee dies or becomes disabled (within the meaning of Code
Section 22(e)(3)) prior to termination of his right to exercise an Option in
accordance with the provisions of his stock option agreement without having
totally exercised the Option, the Option may be exercised, to the extent of the
shares with respect to which the Option could have been exercised by the
optionee on the date of his death or disability, by (i) the optionee's estate or
by the person who acquired the right to exercise the Option by bequest or
inheritance or by reason of the death of the optionee, or (ii) the optionee or
his personal representative in the event of the optionee's disability, provided
the Option is exercised prior to the date of its expiration or not more than one
year from the date of the optionee's death or disability, whichever first
occurs. The date of disability of an optionee shall be determined by the
Committee.

11. AWARD AGREEMENTS

Each Award granted under the Plan shall be evidenced by an Award
agreement between the employee or non-employee director to whom the Award is
granted and the Company, setting forth the number of shares of Common Stock,
units subject to the Award and such other terms and conditions applicable to the
Award not inconsistent with the Plan as the Committee may deem appropriate. The
award agreement for an Option shall also be referred to as a stock option
agreement.

A-4
<PAGE>
12. TAX WITHHOLDING

The Committee may establish such rules and procedures as it considers
desirable in order to satisfy any obligation of the Company or any Subsidiary to
withhold federal income taxes or other taxes with respect to any Award made
under the Plan. Such rules and procedures may provide (i) in the case of Awards
paid in shares of Common Stock, that the person receiving the Award may satisfy
the withholding obligation by instructing the Company to withhold shares of
Common Stock otherwise issuable or transferable upon exercise of such Award in
order to satisfy such withholding obligation and (ii) in the case of an Award
paid in cash, that the withholding obligation shall be satisfied by withholding
the applicable amount and paying the net amount in cash to the participant;
provided that the requirements of Rule 16b-3 promulgated by the Securities and
Exchange Commission, to the extent applicable, must be satisfied with regard to
any withholding pursuant to clause (i).

13. CHANGE OF CONTROL

For the purpose of the Plan, a "Change of Control" shall be deemed to
have occurred if (i) the Company is merged or consolidated with another
corporation and as a result of such merger or consolidation less than 50% of the
outstanding voting securities of the surviving or resulting corporation are
owned in the aggregate by the former shareholders of the Company; (ii) the
Company sells all or substantially all of its assets to another corporation,
which is not a wholly-owned subsidiary of the Company; (iii) any person or group
within the meaning of the Securities Exchange Act of 1934, as amended, acquires
(together with voting securities of the Company held by such person or group)
30% or more of the outstanding voting securities of the Company (whether
directly, indirectly, beneficially or of record) pursuant to any transaction or
combination of transactions; (iv) there is a change of control of the Company of
a nature that would be required to be reported in response to Item 6(e) of
Schedule 14A of Regulation 14A promulgated under the Securities Exchange Act of
1934, as amended, whether or not the Company is then subject to such reporting
requirements; or (v) the individuals who, at the beginning of any period of
twelve consecutive months, constituted the Board of Directors cease, for any
reason, to constitute at least a majority thereof, unless the nomination for
election or election by the Company's shareholders of each new director of the
Company was approved by a vote of at least two-thirds of the directors then
still in office who either were directors at the beginning of such period or
whose election or nomination for election was previously so approved.
Notwithstanding the foregoing, however, a Change of Control shall not be deemed
to have occurred upon the issuance of capital stock by the Company approved by a
vote of at least two-thirds of the directors then in office.

In the event of a Change of Control affecting the Company, then,
notwithstanding any provision of the Plan or of any provisions of any Award
agreements entered into between the Company and any participant to the contrary,
all Awards that have not expired and which are then held by any participant (or
the person or persons to whom any deceased participant's rights have been
transferred) shall, as of such Change of Control, become fully and immediately
vested and exercisable and may be exercised for the remaining term of such
Awards.

14. DILUTION OR OTHER ADJUSTMENT

If the Company is a party to any merger or consolidation, or undergoes
any merger, consolidation, separation, reorganization, liquidation or the like,
the Committee shall have the power to make arrangements, which shall be binding
upon the holders of unexpired Awards, for the substitution of new Awards for, or
the assumption by another corporation of, any unexpired Awards then outstanding
hereunder. In addition, in the event of a reclassification, stock split,
combination of shares, separation (including a spin-off), dividend on shares of
the Common Stock payable in stock or other similar change in capitalization or
in the corporate structure of shares of the Common Stock, the Committee shall
conclusively determine the appropriate adjustment in the option prices of
outstanding Options, and the number and kind of shares or other securities as to
which outstanding Awards shall be exercisable, and in the aggregate number of
shares with respect to which Awards may be granted.

15. TRANSFERABILITY

No Award granted under this Plan shall be sold, pledged, assigned or
transferred other than by will or the laws of descent and distribution, and
Awards shall be exercisable during the employee's lifetime only by the employee.

A-5
<PAGE>
16. AMENDMENT OR TERMINATION

The Committee may at any time amend, suspend or terminate the Plan;
PROVIDED, HOWEVER, that (i) no change in any Awards previously granted may be
made without the consent of the holder thereof and (ii) no amendment (other than
an amendment authorized by Section 14) may be made increasing the aggregate
number of shares of the Common Stock with respect to which Awards may be
granted, reducing the minimum option price at which Options may be granted,
extending the maximum period during which Awards may be exercised or changing
the class of employees eligible to receive Awards hereunder, without the
approval of the holders of a majority of the outstanding voting shares of the
Company.

17. GENERAL PROVISIONS

(a) Nothing contained in the Plan or in Awards granted thereunder shall
confer upon any employee or non-employee director any right to (i) continue in
the employ of the Company or any of its Subsidiaries or continue serving on the
Board of Directors of the Company, (ii) interfere in any way with the right of
the Company or any of its Subsidiaries to terminate his or her employment at any
time or service on the Board.

(b) Nothing contained in the Plan shall confer upon any employee any
right to be granted an Award.

(c) No Awards may be exercised by the holder thereof if such exercise,
and the receipt of cash or stock thereunder, would be, in the opinion of counsel
selected by the Company, contrary to law or the regulations of any duly
constituted authority having jurisdiction over the Plan.

(d) A bona fide leave of absence approved by a duly constituted officer
of the Company or any of its Subsidiaries shall not be considered interruption
or termination of service of any employee for any purposes of the Plan or Awards
granted thereunder, except that no Awards may be granted to an employee while he
or she is on a bona fide leave of absence. No Award recipient shall have any
rights as a shareholder with respect to any shares subject to Awards granted to
him or her under the Plan prior to the date as of which he or she is actually
recorded as the holder of such shares upon the stock records of the Company.

(e) Any Award, which includes Common Stock to be issued or transferred
as part or all of the Award, may be subject to such restrictions, including,
without limitation, restrictions as to transferability and restrictions
constituting substantial risks of forfeiture as the Committee may determine at
the time such Award is granted.

(f) All decisions, determinations and interpretations with respect to
the interpretation and construction of any provision of the Plan made by the
Committee shall be final, binding and conclusive for all purposes. Except to the
extent preempted by federal law, this Plan shall be construed and enforced in
accordance with, and governed by, the laws of the State of Delaware.

(g) The grant of an Award shall not be construed as giving a
participant the right to be retained in the employ of the Company or any
Subsidiary. Further, the Company or a Subsidiary may at any time dismiss a
participant from employment, free from any liability or any claim under the
Plan, unless otherwise expressly provided in the Plan or in any Award.

(h) No employee shall have any rights as a stockholder with respect to
Common Stock covered by his Option until the date a stock certificate is issued
for the Common Stock underlying such Option.

(i) No employee shall exercise the election permitted under Code
Section 83(b) without written approval of the Committee. Any employee doing so
without such approval shall forfeit all Options and/or other Awards issued to
him under this Plan.

(j) Notwithstanding any other provisions of the Plan, if the Committee
finds by a majority vote after full consideration of the facts the employee,
before or after termination of his employment with the Company or its
Subsidiaries for any reason (a) committed or engaged in fraud, embezzlement,
theft, commission of a felony, or proven dishonesty in the course of his
employment by the Company or a Subsidiary, which conduct damaged the Company or
any Subsidiary, or

A-6
<PAGE>
disclosed trade secrets or confidential information of the Company or a
Subsidiary, or (b) participated, engaged in or had a financial or other
interest, whether as an employee, officer, director, consultant, contractor,
equity owner, or otherwise, in any commercial endeavor in the United States
which is competitive with the business of the Company or a Subsidiary without
the written consent of the Company or Subsidiary, the employee shall forfeit all
outstanding Options and all outstanding Awards, and including all exercise
Options and other situations pursuant to which the Company has not yet delivered
a stock certificate. Clause (b) shall not be deemed to have been violated solely
by reason of the employee's ownership of stock or securities of any
publicly-owned corporation, if such ownership is less than 2.5% of the
corporation's outstanding stock or securities.

The decision of the Committee as to the cause of the employee's
discharge (if discharged), the damage done to the Company or a Subsidiary, and
the extent of the employee's competitive activity shall be final. No decision of
the Committee, however, shall affect the finality of any discharge of the
employee by the Company or a Subsidiary in any manner.

18. PLAN NOT A CONTRACT OF EMPLOYMENT.

The Plan is not a contract of employment, and terms of employment shall
not be affected in any way by the Plan or related instruments except as
specifically provided therein. The establishment of the Plan, or the granting of
any Award, shall not be construed as conferring any legal rights for continuance
of employment, nor shall it interfere with the right of the Company or any
subsidiary to discharge any employee.

19. COMPLIANCE WITH APPLICABLE LAW.

Notwithstanding anything herein to the contrary, the Company shall not
be obligated to cause to be issued or transferred any shares of Company Stock
under the Plan until the Company is advised by its counsel that the issuance or
transfer of the shares of Common Stock is in compliance all applicable laws,
regulations of governmental authorities, the requirements of any exchange on
which the shares of Common Stock are listed, and not in conflict with any
contractual covenants of the Company. The Committee may require, as a condition
of the issuance or transfer of shares of Common Stock and in order to ensure
compliance with those laws, regulations, requirements and covenants, that the
shares of Common Stock be subject to such covenants, agreements and
representations as the Committee, in its sole discretion, deems reasonable or
desirable.

20. EFFECTIVE DATE

This Plan, which amends and restates the Company's 1996 Incentive Stock
Option Plan, will become effective upon its approval by the holders of a
majority of the outstanding voting shares of the Company; provided, however,
such amendment shall not affect any grants of options then outstanding. In the
event of the failure to obtain such shareholder approval, the Plan, as proposed
to be amended and restated, shall be null and void and the Company shall have no
liability thereunder, and thereby the Company's 1996 Incentive Stock Option Plan
(the "1996 Plan") will remain in effect. The approval of this Plan will not
amend, alter or otherwise affect the terms and conditions of any awards under
the 1996 Plan which were outstanding as of the date of approval of the Plan by
the Company's Board of Directors.

21. TERMINATION

No Award may be granted under the Plan on or after the date which is
five years following the effective date specified in Section 20, but Awards
previously granted may be exercised in accordance with their terms.

A-7

Exhibit 23.1

INDEPENDENT AUDITORS' CONSENT

We consent to the incorporation by reference in Registration Statement No.
33-90932 on Form S-8 and in Registration Statement No. 333-3132 on Form S-8 of
our report dated March 6, 1998, appearing in the Annual Report on Form 10-K of
Kelley Oil & Gas Corporation for the year ended December 31, 1997.

Deloitte & Touche LLP

Houston, Texas
March 30, 1998

Exhibit 23.2

CONSENT OF H.J. GRUY AND ASSOCIATES, INC.

We hereby consent to the use of the name H.J. Gruy and Associates, Inc. and of
references to H.J. Gruy and Associates, Inc. and to the inclusion of and
references to our report dated February 18, 1998, prepared for Kelley Oil & Gas
Corporation in the Kelley Oil & Gas Corporation Annual Report on Form 10-K for
the year ended December 31, 1997.

H.J. Gruy and Associates, Inc.

/s/ JAMES H. HARTSOCK, PH.D., P.E.
James H. Hartsock, Ph.D., P.E.
Executive Vice President

March 24, 1998
Houston, Texas

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