<PAGE>
   AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON DECEMBER 20, 1996
                                                  REGISTRATION NUMBER 333-
-------------------------------------------------------------------------------
-------------------------------------------------------------------------------
 
                      SECURITIES AND EXCHANGE COMMISSION
                            WASHINGTON, D.C. 20549
 
                                   FORM S-4
 
            REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
 
                         KELLEY OIL & GAS CORPORATION
                            KELLEY OIL CORPORATION
                        KELLEY OPERATING COMPANY, LTD.
            (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
 
<TABLE>
<S>                             <C>                          <C>
           DELAWARE                         1311                 76-0447267
           DELAWARE                         1311                 76-0082502
           DELAWARE                         1311                 76-0156485
 (STATE OR OTHER JURISDICTION
              OF                (PRIMARY STANDARD INDUSTRIAL  (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION)   CLASSIFICATION CODE NUMBER) IDENTIFICATION NO.)
</TABLE>
 
                           601 JEFFERSON, SUITE 1100
                             HOUSTON, TEXAS 77002
                                (713) 652-5200
  (ADDRESS, INCLUDING ZIP CODE, AND TELEPHONE NUMBER, INCLUDING AREA CODE, OF
                   REGISTRANT'S PRINCIPAL EXECUTIVE OFFICES)
 
                                THOMAS E. BAKER
                    GENERAL COUNSEL AND CORPORATE SECRETARY
                         KELLEY OIL & GAS CORPORATION
                           601 JEFFERSON, SUITE 1100
                             HOUSTON, TEXAS 77002
                                (713) 652-5200
(NAME, ADDRESS, INCLUDING ZIP CODE, AND TELEPHONE NUMBER, INCLUDING AREA CODE,
                             OF AGENT FOR SERVICE)
 
                                  Copies to:
                               CHARLES H. STILL
                          FULBRIGHT & JAWORSKI L.L.P.
                           1301 MCKINNEY, SUITE 5100
                           HOUSTON, TEXAS 77010-3095
                                (713) 651-5151
 
  APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE OF THE SECURITIES TO THE
PUBLIC: As soon as practicable after this Registration Statement becomes
effective.
 
  If the securities being registered on this Form are being offered in
connection with the formation of a holding company and there is compliance
with General Instruction G, check the following box. [_]
 
                        CALCULATION OF REGISTRATION FEE
 
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<TABLE>
<S>                       <C>             <C>            <C>            <C>
                                                            PROPOSED      
                                             PROPOSED       MAXIMUM
 TITLE OF EACH CLASS OF       AMOUNT         MAXIMUM       AGGREGATE      AMOUNT OF
    SECURITIES TO BE          TO BE       OFFERING PRICE   OFFERING      REGISTRATION
       REGISTERED           REGISTERED (1)   PER UNIT (2)  PRICE (2)         FEE
-------------------------------------------------------------------------------------
10 3/8% Senior
 Subordinated Notes
 Due 2006, Series B.....   $125,000,000         100.3%   $128,750,000     $39,016
-------------------------------------------------------------------------------------
</TABLE>
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(1) Represents the maximum principal amount of notes exchangeable in the
    exchange offering described herein.
(2) Pursuant to Rule 457(f) under the Securities Act of 1933, the registration
    fee has been calculated based on the average of the bid and asked prices
    as of December 18, 1996, in the Private Offerings, Resales and Trading
    through Automated Linkages (PORTAL) market, of the Registrant's 10 3/8%
    Senior Subordinated Notes Due 2006, Series A, for which the securities
    registered hereby will be exchanged.
 
                               ----------------
 
  THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT
SHALL FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS
REGISTRATION STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH
SECTION 8(A) OF THE SECURITIES ACT OF 1933 OR UNTIL THIS REGISTRATION
STATEMENT SHALL BECOME EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING
PURSUANT TO SAID SECTION 8(A), MAY DETERMINE.
 
-------------------------------------------------------------------------------
-------------------------------------------------------------------------------
<PAGE>
 
                             Cross-Reference Sheet
                           (Pursuant to Rule 404(a))
 
<TABLE>
<CAPTION>
              FORM S-4 ITEM AND CAPTION           LOCATION OR PROSPECTUS CAPTION
              -------------------------           ------------------------------
 <C>  <S>                                        <C>
  1.  Forepart of Registration Statement and
       Outside Front Cover Page of
       Prospectus.............................   Outside Front Cover Page
  2.  Inside Front and Outside Back Cover
       Pages of Prospectus....................   Inside Front Cover Page, Page 3
  3.  Risk Factors, Ratio of Earnings to Fixed
       Charges and Other Information..........   Summary; Risk Factors;
                                                  Selected Consolidated
                                                  Financial Data
  4.  Terms of the Transaction................   Summary; The Exchange Offer;
                                                  Description of the Exchange
                                                  Notes; Certain U.S. Federal
                                                  Income Tax Considerations
  5.  Pro Forma Financial Information.........   Pro Forma Financial Data
  6.  Material Contracts with the Company
       Being Acquired.........................   Not applicable
  7.  Additional Information Required for
       Reoffering by Persons and Parties
       Deemed to Be Underwriters..............   Not applicable
  8.  Interests of Named Experts and Counsel..   Legal Matters; Independent
                                                  Accountants; Independent
                                                  Petroleum Engineers
  9.  Disclosure of Commission Position on
       Indemnification for Securities Act
       Liabilities............................   Not applicable
 10.  Information with Respect to S-3
       Registrants............................   Not applicable
 11.  Incorporation of Certain Information by
       Reference..............................   Not applicable
 12.  Information with Respect to S-2 or S-3
       Registrants............................   Not applicable
 13.  Incorporation of Certain Information by
       Reference..............................   Not applicable
 14.  Information with Respect to Registrants
       Other Than S-3 or S-2 Registrants......   Summary; Selected Consolidated
                                                  Financial Data; Management's
                                                  Discussion and Analysis of
                                                  Financial Condition and
                                                  Results of Operations;
                                                  Business and Properties;
                                                  Consolidated Financial
                                                  Statements
 15.  Information with Respect to S-3
       Companies..............................   Not applicable
 16.  Information with Respect to S-2 or S-3
       Companies..............................   Not applicable
 17.  Information with Respect to Companies
       Other Than S-3 or S-2 Companies........   Not applicable
 18.  Information if Proxies, Consents or
       Authorizations are to be Solicited.....   Not applicable
 19.  Information if Proxies, Consents or
       Authorizations are not to be Solicited
       or in an Exchange Offer................   Principal Stockholders;
                                                  Certain Transactions
</TABLE>
<PAGE>
 
PROSPECTUS
 
                               OFFER TO EXCHANGE
 
                                all outstanding
 
             10 3/8% Senior Subordinated Notes Due 2006, Series A
                  ($125,000,000 principal amount outstanding)
                                      for
             10 3/8% Senior Subordinated Notes Due 2006, Series B
                        ($125,000,000 principal amount)
                                      of
 
                      [KELLEY OIL & GAS CORPORATION LOGO]
 
                               ---------------
 
   The Exchange Offer will expire at 12:00 midnight, New York City time, on
                              , 1997, unless extended.
                               ---------------
 
  Kelley Oil & Gas Corporation, a Delaware corporation (the "Company"), hereby
offers (the "Exchange Offer"), on the terms and subject to the conditions set
forth in this Prospectus and the accompanying Letter of Transmittal (the
"Letter of Transmittal"), to exchange up to an aggregate principal amount of
$125,000,000 of its 10 3/8% Senior Subordinated Notes Due 2006, Series B (the
"Exchange Notes") for an equal principal amount of its outstanding 10 3/8%
Senior Subordinated Notes Due 2006, Series A (the "Outstanding Notes", the
Exchange Notes and the Outstanding Notes are sometimes referred to
collectively as the "Notes"), in integral multiples of $1,000. The Exchange
Notes will be unsecured, general obligations of the Company, subordinated in
right of payment to all Senior Indebtedness (as defined herein) of the Company
and are substantially identical (including principal amount, interest rate,
maturity and redemption rights) to the Outstanding Notes for which they may be
exchanged pursuant to the Exchange Offer, except for certain transfer
restrictions and registration rights relating to the Outstanding Notes and
except for certain interest provisions relating to those rights. As of
September 30, 1996, after giving pro forma effect to the Refinancing, the
Company had $7.0 million Senior Indebtedness outstanding. The Company may
incur additional indebtedness under the New Credit Facility (as defined
herein) in the future, which indebtedness will constitute Senior Indebtedness.
The Exchange Notes will be guaranteed on a senior subordinated basis by the
Subsidiary Guarantors (as defined herein). The Subsidiary Guarantees (as
defined herein) will be general, unsecured obligations of the Subsidiary
Guarantors, subordinated in right of payment to all Senior Indebtedness of the
Subsidiary Guarantors. As of September 30, 1996, after giving pro forma effect
to the Refinancing, the Subsidiary Guarantors would have had no outstanding
indebtedness for borrowed money (other than the Subsidiary Guaranties). The
Outstanding Notes have been, and the Exchange Notes will be, issued under an
Indenture dated as of October 15, 1996 (the "Indenture"), among the Company
and United States Trust Company of New York, as trustee (the "Trustee"). See
"Description of the Exchange Notes". There will be no proceeds to the Company
from the Exchange Offer; however, pursuant to a Registration Agreement dated
as of October 25, 1996 (the "Registration Agreement"), among the Company and
the Placement Agents (as defined herein), the Company will bear certain
offering expenses.
 
  Each broker-dealer that receives Exchange Notes for its own account pursuant
to the Exchange Offer (a "Participating Broker-Dealer") must acknowledge that
it will deliver a prospectus in connection with any resale of Exchange Notes.
The Letter of Transmittal states that by so acknowledging and by delivering a
Prospectus, a broker-dealer will not be deemed to admit that it is an
"underwriter" within the meaning of the Securities Act. This Prospectus, as it
may be amended or supplemented from time to time, may be used by a broker-
dealer in connection with resales of Exchange Notes received in exchange for
Outstanding Notes where the Outstanding Notes were acquired by the broker-
dealer as a result of market-making activities or other trading activities.
The Company has agreed that, for a period of 90 days after the Expiration Date
(as defined herein), it will make this Prospectus available to any broker-
dealer for use in connection with a resale. See "Plan of Distribution".
 
                                                          (continued on page 3)
 
                               ---------------
 
SEE "RISK FACTORS", BEGINNING ON PAGE 17, FOR A DESCRIPTION OF CERTAIN FACTORS
TO BE CONSIDERED BY HOLDERS WHO TENDER OUTSTANDING NOTES IN THE EXCHANGE
OFFER.
 
                               ---------------
 
THESE SECURITIES  HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE  SECURITIES AND
 EXCHANGE  COMMISSION  OR  ANY  STATE   SECURITIES  COMMISSION  NOR  HAS  THE
  SECURITIES  AND EXCHANGE  COMMISSION  OR ANY  STATE  SECURITIES COMMISSION
   PASSED  UPON  THE   ACCURACY  OR   ADEQUACY  OF   THIS  PROSPECTUS.  ANY
             REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
 
                               ---------------
 
                 The date of this Prospectus is         , 1997
<PAGE>
 
 
 
 
 
 
  UNTIL                , 1997 (90 DAYS AFTER COMMENCEMENT OF THIS OFFERING),
ALL DEALERS EFFECTING TRANSACTIONS IN THE EXCHANGE NOTES, WHETHER OR NOT
PARTICIPATING IN THE EXCHANGE OFFER, MAY BE REQUIRED TO DELIVER A PROSPECTUS.
 
                                       2
<PAGE>
 
                               TABLE OF CONTENTS
 
<TABLE>
<CAPTION>
                                      PAGE                                             PAGE 
                                      ----                                             ---- 
<S>                                   <C>        <C>                                   <C>  
Summary..............................   5        Certain Transactions................   71  
Risk Factors.........................  17        Description of the Exchange Notes...   72  
The Exchange Offer...................  24        Certain U.S. Federal Income Tax            
Use of Proceeds......................  33         Considerations.....................  105  
Capitalization.......................  34        Plan of Distribution................  107  
Selected Consolidated Financial                  Legal Matters.......................  108  
 Data................................  35        Independent Accountants.............  108  
Management's Discussion and Analysis             Independent Petroleum Engineers.....  109  
 of Financial Condition and Results              Available Information...............  109  
 of Operations.......................  36        Incorporation of Certain Documents..  110  
Business and Properties..............  45        Glossary............................  111  
Company History......................  61        Index to Consolidated Financial            
Management...........................  63         Statements.........................  F-1   
Principal Stockholders...............  70
</TABLE>
 
                               ---------------
 
(continued from cover page)
 
  The Company will accept for exchange any and all validly tendered
Outstanding Notes on or before 12:00 midnight, New York City time, on
           , 1997, unless extended (the "Expiration Date"). Tenders of
Outstanding Notes may be withdrawn at any time before 12:00 midnight, New York
City time, on the Expiration Date but after that time are irrevocable. United
States Trust Company of New York is acting as Exchange Agent in connection
with the Exchange Offer. The Exchange Offer is not conditioned on any minimum
principal amount of Outstanding Notes being tendered for exchange, but is
otherwise subject to certain customary conditions.
 
  The Exchange Notes will bear interest from the date of issuance of the
Exchange Notes at a rate per annum of 10 3/8% and on the same terms as the
Outstanding Notes. Interest on the Exchange Notes will be payable semiannually
on April 15 and October 15 of each year commencing on the first such date
following the date of issuance of the Exchange Notes. Outstanding Notes that
are accepted for exchange will cease to accrue interest on and after the date
on which interest on the Exchange Notes begins to accrue. Accrued and unpaid
interest on the Outstanding Notes that are tendered in exchange for the
Exchange Notes will be payable on or before the first April 15 or October 15
following the date of issuance of the Exchange Notes.
 
  The Outstanding Notes were sold by the Company on October 29, 1996, to
Morgan Stanley & Co. Incorporated, Chase Securities Inc. and Lazard Freres &
Co. LLC (the "Placement Agents") in transactions not registered under the
Securities Act of 1933 (the "Securities Act") in reliance on the exemption
provided in Section 4(2) of the Securities Act. The Placement Agents
subsequently placed the Outstanding Notes with qualified institutional buyers
in reliance on Rule 144A under the Securities Act. Accordingly, the
Outstanding Notes may not be reoffered, resold or otherwise transferred in the
United States unless so registered or unless an applicable exemption from the
registration requirements of the Securities Act is available. The Exchange
Notes are being offered hereunder in order to satisfy the obligations of the
Company under the Registration Agreement. See "The Exchange Offer".
 
  Based on an interpretation by the staff of the Securities and Exchange
Commission (the "Commission" or the "SEC") set forth in no-action letters
issued to third parties, the Company believes that Exchange Notes issued
pursuant to this Exchange Offer may be offered for resale, resold and
otherwise transferred by a holder who is not an affiliate of the Company
without compliance with the registration and prospectus delivery provisions of
the Securities Act, provided that the holder is acquiring the Exchange Notes
in its ordinary course of business and is not participating in and has no
arrangement or understanding with any person to participate in the
distribution (within the meaning of the Securities Act) of the Exchange Notes.
Persons wishing to exchange Outstanding Notes in the Exchange Offer must
represent to the Company that these conditions have been met.
 
                                       3
<PAGE>
 
  The Company does not intend to list the Exchange Notes on any national
securities exchange or to seek the admission thereof to trading in the
National Association of Securities Dealers Automated Quotation System. The
Placement Agents have advised the Company that they intend to make a market in
the Exchange Notes; however, they are not obligated to do so and any market-
making may be discontinued at any time without notice. Accordingly, no
assurance can be given that an active public or other market will develop for
the Exchange Notes or as to the liquidity of or the trading market for the
Exchange Notes.
 
  Any Outstanding Notes not tendered and accepted in the Exchange Offer will
remain outstanding. To the extent that any Outstanding Notes are tendered and
accepted in the Exchange Offer, a holder's ability to sell untendered
Outstanding Notes could be adversely affected. Following consummation of the
Exchange Offer, the holders of Outstanding Notes will continue to be subject
to the existing restrictions on transfer thereof.
 
  The Company expects that the Exchange Notes issued pursuant to this Exchange
Offer will be issued in the form of a Global Exchange Note (as defined
herein), which will be deposited with, or on behalf of, The Depository Trust
Company ("DTC") and registered in its name or in the name of Cede & Co., its
nominee. Beneficial interests in the Global Exchange Note representing the
Exchange Notes will be shown on, and transfers thereof to qualified
institutional buyers will be effected through, records maintained by DTC and
its participants. After the initial issuance of the Global Exchange Note,
Exchange Notes in certificated form will be issued in exchange for the Global
Exchange Note on the terms set forth in the Indenture. See "Description of
Exchange Notes--Book Entry; Delivery and Form".
 
  No dealer, salesperson or other person has been authorized to give
information or to make any representations not contained in this Prospectus,
and, if given or made, such information or representations must not be relied
on as having been authorized by the Company. This Prospectus does not
constitute an offer to sell or the solicitation of an offer to buy any
security other than the Exchange Notes offered hereby.
 
  THIS PROSPECTUS (THIS "PROSPECTUS") DOES NOT CONSTITUTE AN OFFER TO SELL, OR
A SOLICITATION OF AN OFFER TO BUY, ANY NOTE OFFERED HEREBY BY ANY PERSON IN
ANY JURISDICTION IN WHICH IT IS UNLAWFUL FOR SUCH PERSON TO MAKE SUCH AN OFFER
OR SOLICITATION. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE
HEREUNDER SHALL UNDER ANY CIRCUMSTANCES IMPLY THAT THERE HAS BEEN NO CHANGE IN
THE AFFAIRS OF THE COMPANY OR ITS SUBSIDIARIES OR THAT THE INFORMATION SET
FORTH HEREIN IS CORRECT AS OF ANY DATE SUBSEQUENT TO THE DATE HEREOF.
 
 
                               ---------------
 
  This Prospectus includes "forward-looking statements" within the meaning of
various provisions of the Securities Act and the Securities Exchange Act of
1934 (the "Exchange Act"). All statements, other than statements of historical
facts, included in this Prospectus that address activities, events or
developments that the Company expects or anticipates will or may occur in the
future, including statements regarding estimated future net revenues from oil
and gas reserves and the present value thereof, future capital expenditures
(including the amount and nature thereof), business strategy and measures to
implement strategy, competitive strengths, goals, expansion and growth of the
Company's business and operations, plans, references to future success,
references to intentions as to future matters and other similar matters are
forward-looking statements. These statements are based on certain assumptions
and analyses made by the Company in light of its experience and its perception
of historical trends, current conditions and expected future developments as
well as other factors it believes are appropriate in the circumstances.
However, whether actual results and developments will conform with the
Company's expectations and predictions is subject to a number of risks and
uncertainties, including the risk factors discussed in this Prospectus;
general economic, market or business conditions; the opportunities (or lack
thereof) that may be presented to and pursued by the Company; competitive
actions by other oil and gas companies; changes in laws or regulations; and
other factors, many of which are beyond the control of the Company.
Consequently, all of the forward-looking statements made in this Prospectus
are qualified by these cautionary statements and there can be no assurance
that the actual results or developments anticipated by the Company will be
realized or, even if substantially realized, that they will have the expected
consequences to or effects on the Company or its business or operations.
 
                                       4
<PAGE>
 
                                    SUMMARY
 
  The following summary is qualified in its entirety by, and should be read in
conjunction with, the more detailed information, financial statements and notes
thereto and other data included elsewhere in this Prospectus. As used herein,
references to the "Company" mean Kelley Oil & Gas Corporation, a Delaware
corporation, and its predecessors-in-interest. Certain oil and gas terms used
in this Prospectus are defined in the "Glossary" included herein.
 
                                  THE COMPANY
 
  Kelley Oil & Gas Corporation, an independent energy company, together with
its subsidiaries (collectively, "Kelley"), is engaged in oil and natural gas
exploration, development, production and acquisition. Kelley's activities are
concentrated primarily in two geographic areas: north Louisiana and south
Louisiana. At September 30, 1996, approximately 87% of Kelley's proved reserves
are located on 48,620 gross (23,668 net) acres within four fields in Webster
and Bienville Parishes of north Louisiana, where its activities are focused on
lower-risk development drilling. Substantially all of the balance of Kelley's
proved reserves are located in south Louisiana, primarily in Terrebonne Parish.
Kelley intends to continue its primary emphasis on development drilling in its
north Louisiana fields where it believes it has opportunities for production
growth. Kelley's exploration activities will focus on its existing
leaseholdings in Terrebonne Parish, where the Company believes successful wells
have the potential for larger reserves and production as compared to
development wells in north Louisiana. In that regard, Kelley is utilizing
advanced geophysical techniques to re-evaluate and refine interpretations of
Kelley's 3-D seismic database and has entered into a joint venture to explore
and develop its south Louisiana properties, which the Company believes will
enable it to better manage the risks and costs associated with the exploration
and development of such properties.
 
  At January 1, 1996, Kelley had estimated proved reserves of 196.3 Bcf of
natural gas and 1,387 Mbbls of oil, aggregating 204.6 Bcfe, with 96% (by energy
content) of its proved reserves attributable to natural gas. At such date, the
present value of estimated future net revenues attributable to Kelley's proved
reserves was $175.8 million, of which $76.7 million was attributable to proved
developed producing reserves, $33.4 million was attributable to proved
developed non-producing reserves and $65.6 million was attributable to proved
undeveloped reserves. At January 1, 1996, Kelley had leaseholdings comprising
117,528 gross (59,718 net) developed acres and 56,287 gross (47,333 net)
undeveloped acres. In addition, pursuant to an acquisition effective as of July
1, 1996, Kelley purchased undeveloped reserves located on north Louisiana
properties operated by Kelley, which the Company believes added more than 30
Bcfe to Kelley's proved reserves.
 
  In January 1996, the Company entered into financing and related agreements
(the "Contour Agreements") with Contour Production Company L.L.C. ("Contour"),
the successor to a venture formed in 1993 by Bessemer Holdings L.P.
("Bessemer"), the principal investor, and John F. Bookout to pursue
acquisitions of oil and gas reserves. The Contour Agreements provide for a two-
stage $75.0 million equity investment in the Company by Contour. On February
15, 1996, the first stage of the equity investment was completed through
Contour's $48.0 million purchase of newly issued shares of Common Stock
(representing on such date 49.8% of the voting shares of the Company) (the
"Contour Transaction"). The remaining $27.0 million of Contour's equity
commitment will be invested upon satisfaction of certain conditions, but in no
event later than January 2000.
 
  In connection with the first stage of Contour's investment in the Company,
Mr. Bookout, formerly President and Chief Executive Officer of Shell Oil
Company, was appointed Chairman, President and Chief Executive Officer of the
Company, and certain other experienced oil industry executives were appointed
to senior management positions within the Company. The Company's new senior
management team, in an effort to increase production and cash flow, redirected
Kelley's capital resources towards an accelerated drilling program in north
Louisiana, initiating 45 gross (22.7 net) wells during the period beginning on
the date of the Contour Transaction and ending September 30, 1996. During the
same period, management was successful in reducing
 
                                       5
<PAGE>
 
the cost of drilling in north Louisiana by implementing competitive bidding
procedures for drilling services and by reducing the time required for drilling
wells. All wells initiated by Kelley during such period were completed as
producing wells, except for wells still being drilled at the end of such
period. Kelley's average daily production from its north Louisiana properties
for September 1996, was approximately 59 Mmcfe, compared to an average daily
production of approximately 35 Mmcfe during February 1996. Kelley's total daily
production averaged approximately 77 Mmcfe for September 1996, compared to
approximately 58 Mmcfe per day during February 1996, representing an increase
of 33%.
 
                                    STRATEGY
 
  Kelley's strategy is to increase reserves, production and cash flow in a
cost-efficient manner, primarily through the development and exploration of
Kelley's existing properties and through selective acquisitions of oil and gas
reserves.
 
  Develop Existing Assets. Kelley will focus its efforts primarily on lower-risk
development drilling activities within its existing core properties in the
Vacherie Salt Dome region of north Louisiana, where the Company believes it has
opportunities to profitably increase production and cash flow. Since the
Contour Transaction, the Company's new senior management team has refocused and
accelerated Kelley's north Louisiana drilling program. The Company presently
intends to continue dedicating a significant share of its capital resources to
its north Louisiana fields.
 
  Implement a Disciplined Approach to Exploration. The Company's new senior
management team is implementing a disciplined approach to exploration in south
Louisiana. Utilizing current technology, Kelley continues to re-evaluate and
refine interpretations of its 3-D seismic database, which covers substantially
all of its south Louisiana exploration block, and has entered into a joint
venture that will allow it to share the risks and costs associated with
resuming exploratory drilling operations in the area. In this regard, Kelley,
together with its partner, will focus its exploration efforts in south
Louisiana in the approximately 30,000 gross (27,000 net) acres it holds in the
Houma Embayment area of Terrebonne Parish. To date, operators in this
historically prolific hydrocarbon-producing region have produced in the
aggregate more than six trillion cubic feet of natural gas equivalent.
 
  Pursue Strategic Acquisitions. Kelley will focus its acquisition strategy
primarily on producing oil and gas properties having additional development
potential in order to augment existing production and expand and diversify its
reserve base. Potential acquisitions will be evaluated based upon a number of
factors, including development potential, profit enhancement opportunity,
geographic concentration, operatorship and various reserve and production
attributes. The Company believes that its new senior management team's
experience in evaluating and acquiring oil and gas reserves, together with the
additional financial flexibility provided by the Refinancing (as defined
herein), should enable Kelley to more effectively execute an acquisition
strategy to grow its existing asset base, enhance stockholder value and
increase cash flow.
 
  Reduce Costs. The Company's new senior management team is committed to
achieving and maintaining an efficient cost structure. The initial steps of
Kelley's cost reduction program include the implementation of new information
and business systems, the outsourcing of selected technical and administrative
functions and the utilization of competitive bidding and improved drilling
techniques in north Louisiana to reduce drilling costs.
 
                             COMPETITIVE STRENGTHS
 
  The Company believes that the following competitive strengths will aid in the
successful implementation of its strategy.
 
  Geographic and Operating Focus. Substantially all of Kelley's reserves and
activities are concentrated in north and south Louisiana. The Company believes
its geographic focus enhances profit potential by allowing it
 
                                       6
<PAGE>
 
to manage its large and growing asset base with a relatively small number of
employees. Moreover, the concentration of properties operated by Kelley,
particularly in the Vacherie Salt Dome area of north Louisiana, enables it to
achieve cost and operational efficiencies and to commence recompletion and new
drilling activities quickly and cost-effectively. Kelley is the operator of
properties accounting for approximately 82% of its production at September 30,
1996. As operator, Kelley possesses the ability to enhance profitability by
controlling its operating and overhead expense structure, managing production
performance and regulating capital expenditure projects. During the first nine
months of 1996, Kelley's production expenses for north Louisiana on a per unit
basis were $.24 per Mcfe compared to $.35 per Mcfe during 1995. Although Kelley
also has been successful in reducing aggregate operating costs in south
Louisiana, production expenses on a per unit basis ($.90 per Mcfe during the
first nine months of 1996) have increased due to a decline in production in
such area.
 
  Quality Reserves. Kelley's proved reserves as of January 1, 1996, are
relatively long-lived (9.8 reserves to production ratio). Based on past
production profiles, the Company believes that its north Louisiana wells
ordinarily will produce half of their estimated ultimate reserves in the first
five years of their productive lives (generally in excess of 20 years) and will
produce at lower but more constant rates for the remainder of such lives. From
January 1, 1994 through December 31, 1995, Kelley participated in 47 gross
(18.8 net) wells (70% of which were drilled by Kelley), all of which have been
completed as producing wells, at an average development cost of $.60 per Mcfe
with gross average reserves per well of 4.1 Bcfe. These completed wells tested
at daily rates of up to 16,600 Mcfe and had an average initial daily production
rate of 5,200 Mcfe. During the period beginning with the Contour Transaction
and ending September 30, 1996, Kelley drilled 45 gross (22.7 net) wells in
north Louisiana, which were developed at a lower average cost per Mcfe than
those drilled in 1994 and 1995. The Company believes the high initial
production rates, relatively short pay-back periods and long lives of its north
Louisiana wells provide a solid base from which to pursue its exploration
strategy in south Louisiana as well as its reserve acquisition strategy.
 
  Favorable Price and Cost Structure. Kelley's oil and gas reserves are located
in close proximity to pipeline transportation and key market locations, and,
therefore, generally command favorable prices. In north Louisiana, Kelley is
able to achieve favorable operating margins because lease operating expenses
are generally low as a result of relatively low formation pressures and minimal
liquid hydrocarbon and salt water production. Kelley's south Louisiana
properties are generally closer to transportation and market locations, and
production from these reserves generally receives higher prices because of its
rich condensate content. These higher prices partially offset the relatively
higher operating costs associated with higher formation pressures, inland water
locations and salt water disposal in south Louisiana.
 
  Effective Use of Technology. Kelley applies advanced technology to lower the
risks and costs of exploration and development. The Company, together with its
partner, is re-evaluating and refining Kelley's 3-D seismic database, which
covers 125 square miles, including virtually all of its south Louisiana
exploration prospects. This analysis will increase the possibility of success
and allow for better well placement. Moreover, Kelley invests in computer-aided
exploration and development hardware and software and has the background and
operating experience to engage highly competent and experienced technical
consultants, as needed.
 
  Experienced and Proven Management Team. The four members of the Company's new
senior management team have an average of approximately 30 years of experience
in the oil and gas industry and Kelley's operating managers possess significant
experience in its operating areas. In addition, the new senior management team
has been supported in its undertaking by the substantial equity investment
arising from the Contour Transaction. Through various performance incentive
programs, the Company believes that management, employee and investor interests
are strongly aligned.
 
                                       7
<PAGE>
 
                                THE REFINANCING
 
  Pursuant to an Offer to Purchase and Consent Solicitation dated September 24,
1996, as amended (the "Offer/Solicitation"), the Company offered to purchase
for cash (the "Tender Offer") any and all of its 13 1/2% Senior Notes due 1999
(the "13 1/2% Notes") at a cash price (the "Tender Offer Consideration") equal
to $1,110 per $1,000 principal amount, plus interest accrued and unpaid through
the Payment Date (as defined in the Offer/Solicitation). In conjunction
therewith, the Company also solicited (the "Solicitation") consents to the
adoption of certain amendments to the indenture (the "13 1/2% Indenture")
pursuant to which the 13 1/2% Notes were issued, and offered to pay each holder
of the 13 1/2% Notes who validly consented pursuant to the terms and conditions
of the Offer/Solicitation an amount in cash (the "Consent Payment") equal to
$30 for each $1,000 principal amount of the 13 1/2% Notes so validly
consenting. The Company received the requisite consents to allow it to amend
the 13 1/2% Indenture and amended the 13 1/2% Indenture on October 28, 1996.
The Company also received tenders from holders of approximately $99.6 million
principal amount of 13 1/2% Notes.
 
  On October 29, 1996, the Company issued the Outstanding Notes to the
Placement Agents (the "Note Offering") pursuant to a Placement Agreement dated
October 25, 1996 (the "Placement Agreement"). The Company used substantially
all of the net proceeds from the Note Offering to pay the Tender Offer
Consideration to holders of the 13 1/2% Notes that were validly tendered and
accepted for payment pursuant to the Tender Offer and to pay Consent Payments
to holders of the 13 1/2% Notes who validly consented pursuant to the
Solicitation.
 
  The purpose of the Offer/Solicitation and the issuance of the Outstanding
Notes was to improve the Company's financial flexibility by (i) eliminating the
covenants applicable to the 13 1/2% Notes that might impede future financing
and acquisition transactions, (ii) extending the maturities of the Company's
long-term debt and (iii) replacing senior debt with senior subordinated debt
(which will provide the Company flexibility to pursue additional senior debt
financings).
 
  Effective December 12, 1996, the Company amended its credit facility, agented
by Texas Commerce Bank National Association (the "New Credit Facility"). The
New Credit Facility increased the Company's borrowing base to $57.5 million and
is secured by substantially all of the oil and gas assets of the Company and
its subsidiaries and the proceeds therefrom. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations--Liquidity and
Capital Resources". The Offering, the transactions contemplated by the
Offer/Solicitation and the consummation of the New Credit Facility are referred
to herein collectively as the "Refinancing".
 
                                ----------------
 
  The Company was incorporated in Delaware in 1994. The Company's executive
offices are located at 601 Jefferson, Suite 1100, Houston, Texas 77002, and its
telephone number is (713) 652-5200.
 
 
                                       8
<PAGE>
 
                               THE NOTE OFFERING
 
THE OUTSTANDING NOTES ......  The Outstanding Notes were sold by the Company on
                              October 29, 1996, to the Placement Agents
                              pursuant to the Placement Agreement. The
                              Placement Agents subsequently resold the
                              Outstanding Notes to qualified institutional
                              buyers pursuant to Rule 144A under the Securities
                              Act.
 
REGISTRATION AGREEMENT .....  The Registration Agreement grants the holders of
                              the Outstanding Notes certain exchange and
                              registration rights. The Exchange Offer is
                              intended to satisfy those exchange rights, which
                              terminate on the consummation of the Exchange
                              Offer. If applicable law or applicable
                              interpretations of the staff of the Commission do
                              not permit the Company to effect the Exchange
                              Offer, or in certain other circumstances, the
                              Company has agreed to file a shelf registration
                              (the "Shelf Registration Statement") covering
                              resales of Transfer Restricted Notes (as defined
                              in the Registration Agreement). See "The Exchange
                              Offer--Shelf Registration Statement".
 
                               THE EXCHANGE OFFER
 
SECURITIES OFFERED .........  $125,000,000 aggregate principal amount of 10
                              3/8% Senior Subordinated Notes Due 2006,
                              Series B.
 
THE EXCHANGE OFFER .........  $1,000 principal amount of Exchange Notes in
                              exchange for each $1,000 principal amount of
                              Outstanding Notes. As of the date hereof,
                              $125,000,000 aggregate principal amount of
                              Outstanding Notes are outstanding. The Company
                              will issue the Exchange Notes as soon as
                              practicable after the Expiration Date.
 
                              Based on an interpretation of the staff of the
                              Commission set forth in no-action letters issued
                              to third parties, the Company believes that
                              Exchange Notes issued pursuant to the Exchange
                              Offer in exchange for Outstanding Notes may be
                              offered for resale, resold and otherwise
                              transferred by any holder thereof (other than any
                              holder that is an "affiliate" of the Company
                              within the meaning of Rule 405 under the
                              Securities Act or a Participating Broker-Dealer)
                              without compliance with the registration and
                              prospectus delivery provisions of the Securities
                              Act, provided that the Exchange Notes are
                              acquired in the ordinary course of the holder's
                              business and that the holder does not intend to
                              participate and has no arrangement or
                              understanding with any person to participate in
                              the distribution of the Exchange Notes.
 
                              Each Participating Broker-Dealer must acknowledge
                              that it will deliver a prospectus in connection
                              with any resale of Exchange Notes. A broker-
                              dealer that delivers a prospectus to purchasers
                              in connection with resales will be subject to
                              certain of the civil liability provisions under
                              the Securities Act and will be bound by the
                              provisions of the Registration Agreement
                              (including certain indemnification rights and
                              obligations). This Prospectus, as it may
 
                                       9
<PAGE>
 
                              be amended or supplemented from time to time, may
                              be used by a broker-dealer in connection with
                              resales of Exchange Notes received in exchange
                              for Outstanding Notes where the Outstanding Notes
                              were acquired by the broker-dealer as a result of
                              market-making activities or other trading
                              activities. The Company has agreed that, for a
                              period of 90 days after the Expiration Date, it
                              will use its best efforts to make this Prospectus
                              available to any broker-dealer for use in
                              connection with any resale. See "Plan of
                              Distribution".
 
                              Any holder who tenders in the Exchange Offer with
                              the intention to participate, or for the purpose
                              of participating, in a distribution of the
                              Exchange Notes may not rely on the position of
                              the staff of the Commission enunciated in Exxon
                              Capital Holdings Corporation (available April 13,
                              1989) and Morgan Stanley & Co. Incorporated
                              (available June 5, 1991) or similar no-action
                              letters and, in the absence of an exemption from
                              applicable legislative requirements, must comply
                              with the registration and prospectus delivery
                              requirements of the Securities Act in connection
                              with the resale transaction. Failure to comply
                              with those requirements may result in the holder
                              incurring liability under the Securities Act for
                              which the holder is not indemnified by the
                              Company.
 
EXPIRATION DATE ............  12:00 midnight, New York City time, on
                                          , 1997, unless extended.
 
INTEREST ON THE NOTES ......  The Exchange Notes will bear interest from the
                              date of issuance of the Exchange Notes.
                              Outstanding Notes that are accepted for exchange
                              will cease to accrue interest on and after the
                              date on which interest on the Exchange Notes
                              begins to accrue. Accrued and unpaid interest on
                              the Outstanding Notes that are tendered in
                              exchange for the Exchange Notes will be payable
                              on or before the first April 15 or October 15
                              following the date of issuance of the Exchange
                              Notes.
                               
PROCEDURES FOR TENDERING      
 OUTSTANDING NOTES .........  Each holder of Outstanding Notes wishing to
                              accept the Exchange Offer must complete, sign and
                              date the accompanying Letter of Transmittal (the
                              "Letter of Transmittal"), or a facsimile thereof,
                              in accordance with the instructions contained
                              herein and therein, and mail or otherwise deliver
                              the Letter of Transmittal, or the facsimile,
                              together with the Outstanding Notes and any other
                              required documentation to the Exchange Agent at
                              the address set forth herein. By executing the
                              Letter of Transmittal, each holder will represent
                              to the Company that, among other things, the
                              holder or the person receiving Exchange Notes,
                              whether or not that person is the holder, is
                              acquiring the Exchange Notes in the ordinary
                              course of business and that neither the holder
                              nor any other person has any arrangement or
                              understanding with any person to participate in
                              the distribution of the Exchange Notes. In lieu
                              of physical delivery of the certificates
                              representing Outstanding Notes, tendering holders
                              may transfer notes pursuant to the procedure for
                              book-entry transfer as set forth under "The
                              Exchange Offer--Procedures for Tendering".
 
 
                                       10
<PAGE>
                               
SPECIAL PROCEDURES FOR        
 BENEFICIAL OWNERS .........  Any beneficial owner whose Outstanding Notes are
                              registered in the name of a broker-dealer,
                              commercial bank, trust company or other nominee
                              and who wishes to tender should contact the
                              registered holder of its Outstanding Notes
                              promptly and instruct the registered holder to
                              tender on it's behalf. If such a beneficial owner
                              wishes to tender on it's own behalf, it must,
                              before completing and executing the Letter of
                              Transmittal and delivering its Outstanding Notes,
                              either make appropriate arrangements to register
                              ownership of the Outstanding Notes in it's name
                              or obtain a properly completed bond power from
                              the registered holder. The transfer of registered
                              ownership may take considerable time.

GUARANTEED DELIVERY          
 PROCEDURES ................  Holders of Outstanding Notes who wish to tender
                              their Outstanding Notes and whose Outstanding
                              Notes are not immediately available or who cannot
                              deliver their Outstanding Notes, the Letter of
                              Transmittal or any other documents required by
                              the Letter of Transmittal to the Exchange Agent
                              (or comply with the procedures for book-entry
                              transfer) on or before the Expiration Date must
                              tender their Outstanding Notes according to the
                              guaranteed delivery procedures set forth in "The
                              Exchange Offer--Guaranteed Delivery Procedures".
 
WITHDRAWAL RIGHTS ..........  Tenders may be withdrawn at any time before 12:00
                              midnight, New York City time, on the Expiration
                              Date pursuant to the procedures described under
                              "The Exchange Offer--Withdrawal of Tenders."
 
ACCEPTANCE OF OUTSTANDING
 NOTES AND DELIVERY OF
 EXCHANGE NOTES ............  Subject to certain conditions, the Company will
                              accept for exchange any and all Outstanding Notes
                              that are properly tendered in the Exchange Offer
                              before 12:00 midnight, New York City time, on the
                              Expiration Date. The Exchange Notes issued
                              pursuant to the Exchange Offer will be delivered
                              on the date of issuance of the Exchange Notes.
                              See "The Exchange Offer--Terms of the Exchange
                              Offer".

FEDERAL INCOME TAX           
 CONSIDERATIONS ............  The exchange pursuant to the Exchange Offer
                              should not be a taxable event for federal income
                              tax purposes. See "Certain U.S. Federal Income
                              Tax Considerations".
                              
EFFECT ON HOLDERS OF         
 OUTSTANDING NOTES .........  As a result of the making of this Exchange Offer,
                              the Company will have fulfilled one of its
                              obligations under the Registration Agreement,
                              and, with certain exceptions noted below, holders
                              of Outstanding Notes who do not tender their
                              Outstanding Notes will not have any further
                              registration rights under the Registration
                              Agreement or otherwise. Such holders will
                              continue to hold the untendered Outstanding Notes
                              and will be entitled to all the rights and
                              subject to all the limitations applicable thereto
                              under the Indenture, except to the extent those
                              rights or limitations, by their terms, terminate
                              or cease to have further effect as a result of
                              the
 
                                       11
<PAGE>
 
                              Exchange Offer. All untendered Outstanding Notes
                              will continue to be subject to certain
                              restrictions on transfer. Accordingly, if any
                              Outstanding Notes are tendered and accepted in
                              the Exchange Offer, the trading market of the
                              untendered Outstanding Notes could be adversely
                              affected.

SHELF REGISTRATION           
STATEMENT ..................  If (i) the Company determines that the Exchange
                              Offer may not be consummated as soon as
                              practicable after the Expiration Date because it
                              would violate applicable law or the applicable
                              interpretations of the staff of the Commission,
                              (ii) the Exchange Offer is not consummated within
                              210 days of the date of the Registration
                              Agreement, (iii) the Placement Agents so request
                              with respect to the Outstanding Notes not
                              eligible to be exchanged for Exchange Notes in
                              the Exchange Offer and held by them following
                              consummation of the Exchange Offer or (iv) any
                              holder of an Outstanding Note (other than an
                              Exchanging Dealer (as defined in the Registration
                              Agreement)) is not eligible to participate in the
                              Exchange Offer or, in the case of any holder of
                              Outstanding Notes (other than an Exchanging
                              Dealer) that participates in the Exchange Offer,
                              the holder does not receive freely tradeable
                              Exchange Notes on the date of the exchange for
                              validly tendered (and not withdrawn) Outstanding
                              Notes, the Company has agreed to file and
                              maintain a shelf registration statement that
                              would allow resales of transfer restricted
                              Outstanding Notes or Exchange Notes owned by such
                              holders.
 
EXCHANGE AGENT .............  United States Trust Company of New York.
 
                                       12
<PAGE>
 
                     SUMMARY OF TERMS OF THE EXCHANGE NOTES
 
ISSUER......................  Kelley Oil & Gas Corporation.
 
SECURITIES OFFERED..........  $125 million principal amount of 10 3/8% Senior
                              Subordinated Notes Due 2006, Series B.
 
MATURITY....................  October 15, 2006.
 
INTEREST....................  Payable semiannually in cash, on April 15 and Oc-
                              tober 15, commencing on the first such date fol-
                              lowing the issuance of the Exchange Notes.

OPTIONAL REDEMPTION BY       
 COMPANY....................  The Exchange Notes are redeemable, at the option
                              of the Company, in whole or in part, at any time
                              on or after October 15, 2001, initially at
                              105.188% of their principal amount, plus accrued
                              interest, declining ratably to 100% of their
                              principal amount, plus accrued interest, on or
                              after October 15, 2003.
 
                              In addition, at any time prior to October 15,
                              1999, the Company may redeem in aggregate up to
                              35% of the original principal amount of Notes
                              with the proceeds of one or more Equity Offerings
                              (as defined herein), at 110.375% of their princi-
                              pal amount, plus accrued interest; provided, how-
                              ever, that either at least $75 million aggregate
                              principal amount of Notes must remain outstanding
                              after each such redemption or such redemption
                              must retire the Notes in their entirety. See "De-
                              scription of the Exchange Notes--Optional Redemp-
                              tion".
 
CHANGE OF CONTROL...........  Upon a Change of Control (as defined herein),
                              each holder of Exchange Notes (a "Holder") will
                              have the right to require the Company to repur-
                              chase such Holder's Exchange Notes at a purchase
                              price in cash equal to 101% of the principal
                              amount thereof plus accrued and unpaid interest.
                              See "Description of the Exchange Notes--Certain
                              Covenants--Change of Control".
 
RANKING.....................  The Exchange Notes will be unsecured, general ob-
                              ligations of the Company subordinated in right of
                              payment to all existing and future Senior Indebt-
                              edness (as defined herein) of the Company. The
                              Exchange Notes will rank pari passu in right of
                              payment with any future senior subordinated in-
                              debtedness of the Company and will be senior in
                              right of payment to all existing and future sub-
                              ordinated indebtedness of the Company. After giv-
                              ing pro forma effect to the Refinancing as of
                              September 30, 1996, the Company's aggregate out-
                              standing indebtedness for money borrowed other
                              than the Notes would have been approximately
                              $68.2 million, $7.0 million of which represented
                              Senior Indebtedness and the remainder of which
                              represented subordinated indebtedness. The Com-
                              pany may incur additional indebtedness under the
                              New Credit Facility in the future, and such in-
                              debtedness will constitute Senior Indebtedness.
                              In addition, the Exchange Notes will be effec-
                              tively subordinated to all liabilities of the
                              Company's subsidiaries (other than those of the
                              Subsidiary Guarantors), including trade payables.
                              After giving pro
 
                                       13
<PAGE>
 
                              forma effect to the Refinancing, as of September
                              30, 1996, the Company's subsidiaries (other than
                              the Subsidiary Guarantors) would have had no lia-
                              bilities to Persons (as defined herein) other
                              than the Company and its subsidiaries. See "Risk
                              Factors--Subordination of the Notes" and "De-
                              scription of the Exchange Notes--Ranking".
 
SUBSIDIARY GUARANTIES.......  The Exchange Notes will be irrevocably and uncon-
                              ditionally guaranteed (the "Subsidiary Guaran-
                              ties") on a senior subordinated basis by Kelley
                              Oil Corporation and Kelley Operating Company,
                              Ltd., each a wholly-owned subsidiary of the Com-
                              pany and, in the future, may be guaranteed by
                              other subsidiaries of the Company (collectively,
                              the "Subsidiary Guarantors"). The Subsidiary
                              Guaranties will be general, unsecured obligations
                              of the Subsidiary Guarantors, subordinated in
                              right of payment to all Senior Indebtedness of
                              the Subsidiary Guarantors, including the obliga-
                              tions of the Subsidiary Guarantors under the New
                              Credit Facility. After giving pro forma effect to
                              the Refinancing, as of September 30, 1996, the
                              Subsidiary Guarantors would have had no Senior
                              Indebtedness outstanding, other than to the Com-
                              pany and its subsidiaries. See "Risk Factors--
                              Subordination of the Exchange Notes and the Sub-
                              sidiary Guaranties" and "Description of the Ex-
                              change Notes--Ranking".
 
CERTAIN COVENANTS...........  The indenture pursuant to which the Exchange
                              Notes will be issued (the "Indenture") contains
                              certain covenants for the benefit of the Holders,
                              including, among others, covenants limiting the
                              incurrence of additional indebtedness, the pay-
                              ment of dividends, the redemption of capital
                              stock, the making of certain investments, the re-
                              striction of dividends and other restrictions af-
                              fecting subsidiaries, the issuance of capital
                              stock of subsidiaries, asset sales, certain sale
                              and leaseback transactions, transactions with af-
                              filiates and certain mergers and consolidations.
                              However, these limitations are subject to a num-
                              ber of important qualifications and exceptions.
                              See "Description of the Exchange Notes--Certain
                              Covenants".

BOOK-ENTRY; DELIVERY AND     
 FORM.......................  The Exchange Notes will be represented by one
                              permanent global Exchange Note in definitive,
                              fully registered form deposited with the Trustee
                              as custodian for, and registered in the name of a
                              nominee of, DTC. See "Description of the Exchange
                              Notes--Book-Entry; Delivery and Form".
 
                                  RISK FACTORS
 
  PROSPECTIVE INVESTORS SHOULD CONSIDER CAREFULLY CERTAIN MATTERS RELATING TO
AN INVESTMENT IN THE EXCHANGE NOTES. SEE "RISK FACTORS".
 
                                       14
<PAGE>
 
                         SUMMARY FINANCIAL INFORMATION
 
  The following tables present selected summary historical and unaudited pro
forma financial and operating and reserve data for the Company. 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"). The historical financial information as of and for the years
ended December 31 in each of the four years presented through 1994 is derived
from the audited consolidated financial statements of Kelley Oil. The
Consolidation was treated as a purchase of interests in Kelley Partners by the
Company for financial accounting purposes. Accordingly, the historical
financial information for the year ended December 31, 1995, reflects Kelley
Oil's historical results on a stand-alone basis through the date of the
Consolidation in February 1995, with the results of combined operations
recorded thereafter. The unaudited financial information as of September 30,
1996, and for the nine months ended September 30, 1996 and 1995 has been
prepared by the Company in accordance with generally accepted accounting
principles and reflects all adjustments (consisting of normal recurring
adjustments) necessary for a fair statement in all material respects of the
results for the interim periods presented. Certain financial statement items in
the interim 1995 period have been reclassified to conform to the interim 1996
presentation. This information should be read in conjunction with
"Capitalization", "Selected Consolidated Financial Data", "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
the Consolidated Financial Statements of the Company included elsewhere in this
Prospectus. The pro forma financial information presented below is unaudited
and gives effect to the Consolidation as of January 1, 1994. The pro forma
financial information does not purport to represent what the Company's results
of operations actually would have been had the Consolidation occurred on such
date or to project the Company's results of operations for any future period.
<TABLE>
<CAPTION>
                                                                                                 NINE MONTHS ENDED
                                          YEAR ENDED DECEMBER 31,                                  SEPTEMBER 30,
                       --------------------------------------------------------------------  ---------------------------
                        1991     1992      1993      1994      1995       1994      1995       1995     1995      1996
                       -------  -------  --------  --------  ---------  --------  ---------  --------  -------  --------
                                                                          PRO                            PRO
                                                                         FORMA    PRO FORMA             FORMA
                                                                        --------  ---------            -------
                                                    (IN THOUSANDS, EXCEPT RATIOS)
 <S>                   <C>      <C>      <C>       <C>       <C>        <C>       <C>        <C>       <C>      <C>
 INCOME STATEMENT
  DATA:
 Oil and gas
  revenues..........   $13,179  $18,098  $ 19,711  $ 15,487  $  36,042  $ 42,348  $  38,550  $ 26,284  $28,792  $ 40,201
 Gas marketing
  revenues, net.....     1,216    1,013     1,353     1,335        956        45        958       677      679     1,078
 Gain on sale of oil
  and gas
  properties........       --       --        --        --         777       --         777       777      777       --
 Other income.......       566      819       710       623        404       742        404       310      310       334
 Production
  expenses..........     2,325    3,478     3,993     3,760     10,835    12,318     11,461     7,739    8,365     7,638
 Exploration costs..     3,012    7,126    14,226     7,404     23,387    18,083     23,727    10,523   10,863     4,216
 General and
  administrative
  expenses..........     2,970    3,478     4,079     5,172      7,030     8,308      7,398     4,346    4,714     6,950
 Depreciation,
  depletion and
  amortization......     5,813    9,768    18,857    20,474     35,591    39,727     36,190    23,704   24,303    15,293
 Impairment of oil
  and gas
  properties(1).....        --       --        --        --    150,138        --    150,138       --       --        --
 Restructuring
  expense...........        --       --        --     1,814      1,115     1,814      1,115       --       --      2,000
                       -------  -------  --------  --------  ---------  --------  ---------  --------  -------  --------
  Operating income
   (loss)...........       841   (3,920)  (19,381)  (21,179)  (189,917)  (37,115)  (189,340)  (18,264) (17,687)    5,516
 Interest income....       587      567       796       793        582       851        587       417      422       604
 Interest expense
  and other debt
  expenses..........       950    2,684     6,638     4,571     21,956    12,361     22,763    15,137   15,944    18,376
                       -------  -------  --------  --------  ---------  --------  ---------  --------  -------  --------
  Net income (loss)
   before income
   taxes............       478   (6,037)  (25,223)  (24,957)  (211,291)  (48,625)  (211,516)  (32,984) (33,209)  (12,256)
 Provision (benefit)
  for taxes                 25   (1,071)       --        --         --        --         --        --       --        --
                       -------  -------  --------  --------  ---------  --------  ---------  --------  -------  --------
  Net Income (loss)        453   (4,966)  (25,223)  (24,957)  (211,291)  (48,625)  (211,516)  (32,984) (33,209)  (12,256)
                       -------  -------  --------  --------  ---------  --------  ---------  --------  -------  --------
 Less: cumulative
  preferred stock
  dividends.........       770      729       894     2,905      6,607     4,611      7,033     4,867    5,293       --
                       -------  -------  --------  --------  ---------  --------  ---------  --------  -------  --------
  Net loss
   applicable to
   common stock.....   $  (317) $(5,695) $(26,117) $(27,862) $(217,898) $(53,236) $(218,549) $(37,851) $38,502  $(12,256)
                       =======  =======  ========  ========  =========  ========  =========  ========  =======  ========
 OTHER DATA:
 EBITDA(2) .........   $ 9,666  $12,974  $ 13,702  $  8,513  $  20,314  $ 22,509  $  21,830  $ 15,963  $17,479  $ 27,025
 Cash interest
  expense(3)........       892    2,517     3,686     2,739     15,637     9,524     16,360    10,935   11,641    14,335
 Ratio of EBITDA to
  cash interest
  expense...........      10.8x     5.2x      3.7x      3.1x       1.3x      2.4x       1.3x      1.5x     1.5x      1.9x
 Ratio of net debt
  to EBITDA(4)......        .7x     2.7x      1.8x      3.6x       7.8x      5.3x       7.3x      6.4x     5.8x      4.2x
 Ratio of earnings
  to fixed
  charges(5)........       1.9x                                                                                      1.3x
 ADJUSTMENTS FOR THE
  REFINANCING:
 Cash interest
  expense(6)........                                                              $  16,104  $ 10,797  $11,503  $ 13,981
 Ratio of EBITDA to
  cash interest
  expense(6)........                                                                    1.4x      1.5x     1.5x      1.9x
 Ratio of net debt
  to EBITDA(4)(6)...                                                                    8.4x      7.5x     6.9x      4.8x
 CAPITAL
  EXPENDITURES(7)...   $23,360  $30,267  $ 38,602  $ 42,323  $  47,005  $ 77,743  $  48,578  $ 32,295  $33,868  $ 28,389
</TABLE>
 
<TABLE>
<CAPTION>
                                                        AS OF       AS OF SEPTEMBER 30, 1996
                                                     DECEMBER 31, -----------------------------
                                                         1995       HISTORICAL   AS ADJUSTED(6)
                                                     ------------ -------------- --------------
                                                                  (IN THOUSANDS)
<S>                                                  <C>          <C>            <C>
BALANCE SHEET DATA:
Total assets.......................................    $151,342      $179,421       $181,763
Working capital (deficit)..........................      (9,233)      (17,062)       (15,803)
Property and equipment, net .......................     128,642       155,502        155,502
Total long-term debt...............................     164,980       153,349        176,776
Stockholders' deficit(8)...........................     (45,568)      (13,835)       (30,961)
</TABLE>
 
                                       15
<PAGE>
 
                       SUMMARY OPERATING AND RESERVE DATA
 
<TABLE>
<CAPTION>
                                        YEAR ENDED DECEMBER 31,
                                        -------------------------    NINE MONTHS
                                           1994          1995           ENDED
                                        -----------   -----------   SEPTEMBER 30,
                                         PRO FORMA     PRO FORMA        1996
                                        -----------   -----------   -------------
<S>                                     <C>           <C>           <C>
PRODUCTION DATA:
  Oil and other liquid hydrocarbons
   (Mbbls).............................         446           348          181
  Natural gas (Mmcf)...................      18,141        18,828       16,221
  Natural gas equivalent (Mmcfe).......      20,817        20,916       17,307
AVERAGE SALES PRICE PER UNIT:
  Oil and other liquid hydrocarbons
   (per Bbl)........................... $     16.30   $     17.31      $ 21.29
  Natural gas (per Mcf, including
   effects of hedging).................        1.87          1.72         2.27
  Natural gas (per Mcf, excluding
   effects of hedging).................        1.88          1.65         2.35
  Natural gas equivalent (per Mcfe,
   including effects of hedging).......        2.03          1.84         2.35
COSTS PER MCFE:
  Production expenses.................. $       .59   $       .55      $   .44
  General and administrative expenses..         .40           .35          .40
  Depreciation, depletion and
   amortization........................        1.91          1.73          .88
  Average finding and development
   costs(9)............................        1.05          1.54
PROVED RESERVES:
  Total proved reserves (Mmcfe)........     240,534       204,595
  Reserves to production ratio(10).....        11.6x          9.8x
  Present value of estimated future net
   revenues (in thousands)(11)......... $   163,615      $175,761
  Standardized measure of discounted
   net cash flows (in thousands)(12)...     160,602       171,052
</TABLE>
--------
(1) Reflects noncash impairment charges against the carrying value of proved
    and unproved properties under Financial Accounting Standards Board's
    Statement ("FAS") 121. See "Management's Discussion and Analysis of
    Financial Condition and Results of Operations" and the Company's
    Consolidated Financial Statements included elsewhere in this Offering
    Memorandum.
(2) EBITDA is calculated as operating income before interest expense and other
    debt expenses, income taxes, exploration costs, restructuring expense,
    depletion, depreciation, amortization and impairment of oil and gas
    properties. EBITDA is not a measure of cash flow as determined by generally
    accepted accounting principles ("GAAP"). The Company has included
    information concerning EBITDA because EBITDA is a measure used by certain
    investors in determining a company's historical ability to service its
    indebtedness. EBITDA should not be considered as an alternative to, or more
    meaningful than, net income or cash flow as determined in accordance with
    GAAP as an indicator of Kelley's operating performance or liquidity. EBITDA
    is not necessarily comparable to a similarly titled measure of another
    company. The New Credit Facility requires the Company to maintain certain
    financial ratios related to EBITDA, and the Indenture limits the Company's
    ability to incur certain indebtedness, pay dividends and engage in certain
    other transactions if certain financial ratios related to EBITDA are not
    met. See "Management's Discussion and Analysis of Financial Condition and
    Results of Operations--Liquidity and Capital Resources" and "Description of
    the Exchange Notes--Certain Covenants".
(3) Cash interest expense consists of interest expense and other debt expenses
    less accretion of original issue discount, accretion of debt valuation
    discount, amortization of deferred debt issuance costs and costs associated
    with the conversion of debentures.
(4) For purposes of nine month periods, the ratio of net debt to EBITDA was
    calculated utilizing annualized EBITDA for such period. Net debt is
    outstanding debt less cash.
(5) For purposes of computing the ratio of earnings to fixed charges, earnings
    consist of pre-tax income from continuing operations plus fixed charges.
    Fixed charges consist of interest expense and other debt expenses. For the
    years ended December 31, 1992 through 1995, pre-tax income from continuing
    operations was insufficient to cover fixed charges by $6.6 million, $26.0
    million, $25.8 million and $211.9 million, respectively, and by $50.0
    million, $212.1 million, $33.4 million and $33.6 million for the pro forma
    years ended December 31, 1994 and 1995, for the nine months ended September
    30, 1995, and the pro forma nine months ended September 30, 1995,
    respectively.
(6) As adjusted to give pro forma effect to the Refinancing.
(7) Excludes expenditures on the acquisition of proved properties, the
    Consolidation and capitalized overhead.
(8) Includes extraordinary loss of $17.1 million related to the excess of the
    aggregate purchase price of the 13 1/2% Notes (including Consent Payments)
    over the carrying value of the 13 1/2% Notes as of September 30, 1996.
(9) Average finding and development cost per Mcfe is calculated by dividing (A)
    capital expenditures (including future capital expenditures associated with
    reserve additions but excluding capitalized overhead and expenditures to
    acquire proved properties) relating to the properties which have been
    evaluated during the period by (B) the ultimate reserve additions
    (excluding reserve additions from the acquisition of proved properties)
    attributable to such properties for the same period.
(10) The reserves to production ratio is calculated by dividing the total
     proved reserves as of a specific date by production for the twelve-month
     period immediately preceding such date. See "Glossary".
(11) Computed in accordance with SEC regulations before consideration of future
     income taxes, general and administrative expenses and interest expense.
(12) Computed in accordance with SEC regulations.
--------
Note: Comparative annual reserve replacement ratios are not presented because
      such data would not be meaningful as a result of the Consolidation.
 
                                       16
<PAGE>
 
                                 RISK FACTORS
 
  Prospective investors should consider carefully the following factors, as
well as the other information contained in this Prospectus, in evaluating an
investment in the Exchange Notes. This Prospectus contains forward-looking
statements of the Company. The Company cautions prospective investors that the
following important factors could affect the Company's actual results in the
future.
 
SUBSTANTIAL LEVERAGE
 
  As of September 30, 1996, after giving pro forma effect to the Refinancing,
the Company would have had total indebtedness for money borrowed of
approximately $176.8 million and stockholders' deficit of approximately $31.0
million. The Company intends to incur additional indebtedness for money
borrowed in the future under the New Credit Facility as it executes its
strategy for acquisition, exploration and development of oil and gas reserves.
Moreover, although the Indenture contains covenants that limit the incurrence
by the Company and its subsidiaries of additional indebtedness, such
limitations are subject to a number of important qualifications and
exceptions. In addition, the accretion of principal of a non interest-bearing
or other discount security is not treated as the incurrence of indebtedness
under the Indenture. See "Description of the Exchange Notes--Certain
Covenants".
 
  The Company's leverage could have important consequences to the holders of
the Exchange Notes, including the following: (i) the Company's ability to
obtain additional financing for working capital, capital expenditures,
acquisitions or general corporate purposes may be impaired in the future; (ii)
a substantial portion of the Company's cash flow from operations will be
required for the payment of principal and interest on its indebtedness for
money borrowed, thereby reducing the funds available to the Company for
Kelley's operations, acquisitions and other purposes; (iii) the Company is
substantially more leveraged than certain of its competitors, which may place
the Company at a competitive disadvantage; and (iv) the Company's substantial
degree of leverage may hinder its ability to adjust rapidly to changing market
conditions and could make it more vulnerable in the event of a downturn in
general economic conditions or its business. In addition, certain of the
Company's borrowings are and will continue to be at variable rates of
interest, which exposes the Company to the risk of increased interest rates.
See "--Substantial Capital Requirements", "Capitalization", "Selected
Consolidated Financial Data" and "Management's Discussion and Analysis of
Financial Condition and Results of Operations".
 
  The Company's ability to make scheduled payments of principal of, to pay
interest on or to refinance its indebtedness for money borrowed (including the
Exchange Notes) 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. There can be no assurance
that Kelley's business will generate sufficient cash flow from operations or
that future credit will be available in an amount sufficient to enable the
Company to service its indebtedness for money borrowed, including the Exchange
Notes, or make necessary capital expenditures. See "Management's Discussion
and Analysis of Financial Condition and Results of Operations--Liquidity and
Capital Resources".
 
DEPLETION OF RESERVES; NECESSITY OF SUCCESSFUL EXPLORATION AND DEVELOPMENT
 
  Producing oil and natural gas reservoirs generally are characterized by
declining production rates that vary depending upon reservoir characteristics
and other factors. Kelley's future oil and natural gas reserves and
production, and, therefore, cash flow and income, are highly dependent upon
Kelley's success in efficiently developing its current reserves and acquiring
additional reserves that are economically recoverable. At September 30, 1996,
approximately 87% of Kelley's proved reserves were located within four fields
in Webster and Bienville Parishes of north Louisiana. Without reserve
additions in excess of production through successful acquisition and
development activities, Kelley's reserves and production will decline. There
can be no assurance that Kelley will be able to develop or acquire additional
reserves to replace its current and future production.
 
                                      17
<PAGE>
 
SUBSTANTIAL CAPITAL REQUIREMENTS
 
  Kelley is dependent upon its ability to obtain financing for acquiring,
exploring and developing oil and natural gas properties beyond its internally
generated cash flow. Historically, Kelley has financed these activities
primarily through the issuance of debt and equity securities, through various
credit facilities and with internally generated funds. Kelley currently has
plans for substantial capital expenditures to continue its acquisition and
development activities. The Company expects to utilize the New Credit Facility
to borrow funds required from time to time to supplement its own available
cash. If revenues or the Company's borrowing base decrease as a result of
lower oil and gas prices, operating difficulties or declines in reserves, the
Company's ability to expend the capital necessary to undertake or complete
future activities may be limited. No assurances can be given that the Company
will have adequate funds available to it under the New Credit Facility to
carry out its strategy or that the Company will be able to make any mandatory
principal payments required by the lenders under such facility. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources".
 
VOLATILITY OF OIL, NATURAL GAS AND NATURAL GAS LIQUIDS PRICES
 
  Kelley's financial results are affected significantly by the price received
for Kelley's oil, natural gas and natural gas liquids production.
Historically, the markets for oil, natural gas and natural gas liquids have
been volatile and are likely to continue to be volatile in the future. The
prices received by Kelley for its oil, natural gas and natural gas liquids
production and the levels of such production are subject to wide fluctuations
and depend on numerous factors beyond Kelley's control, including market
uncertainty, changes in global supply of and demand for oil, natural gas and
natural gas liquids, weather conditions, the condition of the United States
economy (particularly the manufacturing sector), the price and quantity of
foreign imports, the price and availability of alternative fuels, political
conditions (including embargoes) in or affecting other oil-producing and
natural gas-producing countries, the actions of the Organization of Petroleum
Exporting Countries and domestic government regulation, legislation and
policies. Kelley's future financial condition and results of operations will
be dependent, in part, upon the prices received for Kelley's oil and natural
gas production, as well as the costs of finding, acquiring, developing and
producing reserves. If oil and natural gas prices fall materially below their
current levels, the availability of funds and the Company's ability to repay
outstanding amounts under bank credit facilities and the Notes could be
materially adversely affected. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations".
 
RESTRICTIVE DEBT COVENANTS
 
  The Company is subject to a number of significant covenants that, among
other things, restrict the ability of Kelley to dispose of assets, incur
additional indebtedness, repay other indebtedness, pay dividends, enter into
certain investments or acquisitions, repurchase or redeem capital stock,
engage in mergers or consolidations, or engage in certain transactions with
subsidiaries and affiliates and that otherwise restrict corporate activities.
There can be no assurance that such restrictions will not adversely affect the
Company's ability to finance its future operations or capital needs or engage
in other business activities that may be in the interest of the Company. In
addition, the New Credit Facility requires the Company to maintain compliance
with certain financial ratios. The ability of the Company to comply with such
ratios may be affected by events beyond the Company's control. A breach of any
of these covenants or the inability of the Company to comply with the required
financial ratios could result in a default under bank credit facilities. In
the event of any such default, all borrowings outstanding under the New Credit
Facility, together with accrued interest and other fees, could be declared due
and payable and the Company could be required to sell assets and apply all of
its available cash to repay such borrowings. The indebtedness under the New
Credit Facility is secured by substantially all of the oil and gas assets of
the Company and its subsidiaries and the proceeds therefrom, and, as a result,
the lenders thereunder would have a claim against such assets prior to other
creditors of the Company and its subsidiaries, including holders of the
Exchange Notes. If the indebtedness under the New Credit Facility or any other
indebtedness of the Company were to be accelerated, there can be no assurance
that the assets of the Company would be sufficient to repay such indebtedness
in full. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations--Liquidity and Capital Resources".
 
                                      18
<PAGE>
 
UNCERTAINTIES IN ESTIMATING RESERVES AND FUTURE NET REVENUES
 
  There are numerous uncertainties not only in acquiring valuable oil and gas
prospects and successfully exploring and developing them but also 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 Kelley. The reserve
data set forth in this Prospectus are only estimates. Reserve estimates are
inherently imprecise and may be expected to change as additional information
becomes available. Furthermore, estimates of oil and gas reserves, of
necessity, are projections based on engineering data, and there are
uncertainties inherent in the interpretation of such data as well as the
projection of future rates of production and the timing of development
expenditures. 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 revenues 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 in this Prospectus will
ultimately be produced or that the proved undeveloped reserves set forth in
this Prospectus will be developed within the periods anticipated. It is likely
that variances from the estimates will be material. In addition, the estimates
of future net revenues from proved reserves of Kelley and the present value
thereof are based upon certain assumptions about future production levels,
prices and costs that may not be correct when judged against actual subsequent
experience. The Company emphasizes with respect to the estimates prepared by
independent petroleum engineers that the discounted future net revenues should
not be construed as representative of the fair market value of the proved
reserves owned by Kelley since estimated future net revenues 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. Actual results will differ, and are likely to differ
materially, from the results estimated. Kelley's operations in south Louisiana
in recent years are illustrative of these uncertainties. Downward revisions
were made to Kelley's estimated proved reserves in south Louisiana in 1993 and
1995, which revisions had an adverse effect on the Company's asset base.
Accordingly, potential investors in the Exchange Notes are cautioned not to
place undue reliance on the reserve data included in this Prospectus.
 
BUSINESS RISKS; OPERATING HAZARDS AND UNINSURED RISKS
 
  Oil and gas drilling activities are subject to numerous risks, including the
risk that no commercially viable oil or natural gas production will be
obtained, and many of such risks are beyond Kelley's control. The decision to
purchase, explore or develop a prospect or property will depend in part on the
evaluation of data obtained through geophysical and geological analyses,
production data and engineering studies, the results of which are often
inconclusive or subject to varying interpretations. The cost of drilling,
completing and operating wells is often uncertain, and overruns in budgeted
expenditures are common risks that can make a particular project uneconomical.
Also, technical problems encountered in actual drilling, completion and
workover activities can delay such activity and add substantial cost 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. Although to date Kelley has not
been materially adversely affected by these recent increased costs, there can
be no assurance that costs will not increase further or that necessary
equipment and services will be available at economical prices.
 
 
                                      19
<PAGE>
 
  The availability of a ready market for Kelley's oil and natural gas
production also depends on a number of factors, including the demand for and
supply of oil and natural gas and the proximity of reserves to pipelines or
trucking and terminal facilities. Natural gas wells may be shut in for lack of
a market or because of inadequacy or unavailability of natural gas pipeline or
gathering system capacity.
 
  Kelley's oil and natural gas business also is subject to all of the
operating risks associated with the drilling for and production of oil and
natural gas, including, but not limited to, uncontrollable flows of oil,
natural gas, brine or well fluids into the environment (including groundwater
and shoreline contamination), blowouts, cratering, mechanical difficulties,
fires, explosions, pollution and other risks, any of which could result in
substantial losses to Kelley. Although Kelley maintains insurance at levels
that it believes are consistent with industry practices, it is not fully
insured against all risks. Losses and liabilities arising from uninsured and
underinsured events could have a material adverse effect on the financial
condition and operations of Kelley.
 
GOVERNMENT LAWS AND REGULATIONS
 
  Kelley's operations are affected from time to time in varying degrees by
political developments and federal and state laws and regulations. In
particular, oil and natural gas production, operations and economics are or
have been affected by price controls, taxes and other laws relating to the oil
and natural gas industry, by changes in such laws and by changes in
administrative regulations. The Company cannot predict how existing laws and
regulations may be interpreted by enforcement agencies or court rulings,
whether additional laws and regulations will be adopted or the effect such
changes may have on Kelley's business or financial condition. See "Business
and Properties--Regulation".
 
  Kelley's operations are subject to complex and constantly changing
environmental laws and regulations adopted by federal, state and local
governmental authorities. The discharge of oil, natural gas, oil and gas
exploration and production wastes or other pollutants into the air, soil or
water may give rise to liabilities on the part of Kelley to the government and
third parties and may require Kelley to incur costs of remediation. No
assurance can be given that existing environmental laws or regulations, as
currently interpreted or reinterpreted in the future, or future laws or
regulations, will not materially adversely affect Kelley's operations and
financial condition or that material indemnity claims will not arise against
Kelley with respect to properties acquired or sold by Kelley. See "Business
and Properties--Regulation".
 
RISKS OF HEDGING TRANSACTIONS
 
  Kelley regularly enters into hedging transactions for its natural gas
production and likely will continue to do so in the future. Such transactions
may limit potential gains by Kelley if oil and natural gas prices were to rise
substantially over the price established by the hedges and may expose Kelley
to the risk of financial loss in certain circumstances, including possibly
instances where Kelley's production is less than expected or there is an
unexpected event materially affecting prices. The natural gas swap agreements
generally provide for Kelley to receive or make counterparty payments on the
differential between a fixed price and a variable indexed price for natural
gas. Kelley is exposed to the credit risk of nonperformance by its hedging
counterparties, which generally can be quantified as the amount of unrealized
gains under the contracts. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations--Results of Operations" and Note
12 to the Consolidated Financial Statements of the Company included in this
Prospectus.
 
COMPETITION
 
  Kelley operates in a highly competitive environment with respect to
acquiring reserves, marketing oil and natural gas and securing trained
personnel. Many of Kelley's larger competitors possess and employ financial
and personnel resources substantially greater than those available to Kelley.
Such companies may be able to pay more for productive oil and natural gas
properties and to define, evaluate, bid for and purchase a greater number of
properties than Kelley's financial or personnel resources permit. Kelley's
ability to acquire additional reserves in the future will be dependent upon
its ability to evaluate and select suitable properties and to consummate
 
                                      20
<PAGE>
 
transactions in a highly competitive environment. In addition, there is
substantial competition for capital available for investment in the oil and
natural gas industry. There can be no assurance that Kelley will be able to
compete successfully in the future in acquiring reserves, developing reserves,
marketing hydrocarbons, attracting and retaining quality personnel, and
raising additional capital. See "Business and Properties--Competition".
 
DEPENDENCE ON KEY PERSONNEL
 
  The Company believes that its current operations and future prospects are
dependent to a significant extent upon the efforts of several members of its
new senior management team, none of whom have been with the Company for more
than one year. The loss of the services of certain of these key individuals
could have an adverse effect upon the Company. The Company currently does not
maintain insurance against the loss of any of these individuals.
 
SUBORDINATION OF THE EXCHANGE NOTES
 
  The Exchange Notes will be subordinated in right of payment to all existing
and future Senior Indebtedness of the Company, which includes all indebtedness
under the New Credit Facility. As of September 30, 1996, after giving pro
forma effect to the Refinancing, the Company would have had $7.0 million of
Senior Indebtedness outstanding and would have had up to $50.5 million
available under the New Credit Facility, which, if borrowed, would be Senior
Indebtedness. The Company currently conducts business through subsidiaries.
Claims of creditors of the Company's subsidiaries, including trade creditors,
secured creditors and creditors holding indebtedness and guarantees issued by
such subsidiaries, and claims of preferred stockholders (if any) of such
subsidiaries, generally will have priority with respect to the assets and
earnings of such subsidiaries over the claims of creditors of the Company,
including holders of the Exchange Notes, even if such obligations do not
constitute Senior Indebtedness of such subsidiaries. However, the Exchange
Notes will be guaranteed by certain subsidiaries of the Company. See
"Description of the Exchange Notes--Certain Covenants--Subsidiary Guaranties".
Such guarantees, however, will be subordinate in right of payment to any
Senior Indebtedness of such subsidiaries. Although the Indenture limits the
incurrence of Indebtedness and preferred stock of certain subsidiaries, such
limitation is subject to a number of significant qualifications. Moreover, the
Indenture does not impose any limitation on the incurrence by subsidiaries of
liabilities that are not considered Indebtedness under the Indenture. See
"Description of the Exchange Notes--Certain Covenants--Limitation on
Indebtedness".
 
  The obligations of each Subsidiary Guarantor (as defined herein) under its
guaranty will be senior subordinated obligations. As such, the rights of
holders of the Exchange Notes to receive payment by a Subsidiary Guarantor
will be subordinated in right of payment to the rights of holders of Senior
Indebtedness of such Subsidiary Guarantor. The terms of the subordination with
respect to the Company's obligations under the Exchange Notes will apply
equally to a Subsidiary Guarantor and the obligations of such Subsidiary
Guarantor under its guaranty.
 
  In the event of liquidation, dissolution, reorganization, bankruptcy or any
similar proceeding regarding the Company, the assets of the Company will be
available to pay obligations on the Exchange Notes only after the Senior
Indebtedness of the Company has been paid in full. Accordingly, there may not
be sufficient funds remaining to pay amounts due on all or any of the Exchange
Notes. In addition, the subordination provisions of the Indenture provide that
no cash payment may be made with respect to the Exchange Notes during the
continuance of a payment default under any Senior Indebtedness of the Company.
Furthermore, if certain non-payment defaults exist with respect to certain
Senior Indebtedness of the Company, the holders of such Senior Indebtedness
will be able to prevent payments on the Exchange Notes for certain periods of
time. See "Description of the Exchange Notes--Ranking".
 
PAYMENT UPON A CHANGE OF CONTROL
 
  Upon the occurrence of a Change of Control, each holder of the Exchange
Notes may require the Company to repurchase all or a portion of such holder's
Exchange Notes at 101% of the principal amount of the Exchange
 
                                      21
<PAGE>
 
Notes, together with accrued and unpaid interest to the date of repurchase.
The Indenture requires that, prior to such a repurchase, the Company must
either repay all outstanding Senior Indebtedness or obtain any required
consents to such repurchase. If a Change of Control were to occur, the Company
may not have the financial resources to repay all of the Senior Indebtedness,
the Exchange Notes and any other indebtedness that would become payable upon
the occurrence of such Change of Control. See "--Subordination of the Exchange
Notes" and "Description of the Exchange Notes--Certain Covenants--Change of
Control".
 
FRAUDULENT TRANSFER LAWS
 
  Under federal or state fraudulent transfer laws, if a court of competent
jurisdiction were to find, in a lawsuit by an unpaid creditor or a
representative of creditors, such as a trustee in bankruptcy or a debtor-in-
possession, that the Company issued the Exchange Notes with the intent to
hinder, delay or defraud present or future creditors, or received less than a
reasonably equivalent value or fair consideration for any such indebtedness,
and at the time of such incurrence (i) was insolvent, (ii) was rendered
insolvent by reason of such incurrence, (iii) was engaged or about to engage
in a business or transaction for which its remaining assets constituted
unreasonably small capital to carry on its business or (iv) intended to incur,
or believed or reasonably should have believed that it would incur, debts
beyond its ability to pay as such debts matured, such court could avoid the
Company's obligations to the holders of the Exchange Notes, subordinate the
Company's obligations to the holders of the Exchange Notes to all other
indebtedness of the Company or take other action detrimental to the holders of
the Exchange Notes. In that event, there can be no assurance that any
repayment on the Exchange Notes could ever be recovered by the holders of the
Exchange Notes. Any Subsidiary Guaranty may also be subject to challenge under
fraudulent transfer laws and, in any case, will be limited to amounts that any
such Subsidiary Guarantor can guarantee without violating such laws. See
"Description of the Exchange Notes--Certain Definitions--Subsidiary Guaranty".
 
LACK OF PUBLIC MARKET FOR THE EXCHANGE NOTES
 
  The Outstanding Notes currently are owned by a relatively small number of
beneficial owners. The Outstanding Notes have not been registered under the
Securities Act and are subject to significant restrictions on resale. The
Exchange Notes will constitute a new issue of securities with no established
trading market. The Company does not intend to list the Outstanding Notes or
the Exchange Notes on any national securities exchange or to seek the
admission thereof to trading in the National Association of Securities Dealers
Automated Quotation System. The Company has been advised by the Placement
Agents that, following consummation of the Exchange Offer, they currently
intend to make a market in the Exchange Notes. However, the Placement Agents
are not obligated to do so, and any market making activity with respect to the
Exchange Notes may be discontinued at any time without notice. If commenced,
such market making activity will be subject to the limits imposed in the
Exchange Act, and may be limited during the Exchange Offer or the pendency of
the Shelf Registration Statement. Accordingly no assurance can be given that
an active public or other market will develop for the Exchange Notes or as to
the liquidity of or the trading market for the Exchange Notes.
 
EXCHANGE OFFER PROCEDURES
 
  Issuance of the Exchange Notes in exchange for Outstanding Notes pursuant to
the Exchange Offer will be made only after a timely receipt by the Company of
Outstanding Notes, a properly completed and duly executed Letter of
Transmittal and all other required documents. Therefore, holders of the
Outstanding Notes desiring to tender their Outstanding Notes in exchange for
Exchange Notes should allow sufficient time to ensure timely delivery. The
Company is under no duty to give notification of defects or irregularities
with respect to the tenders of Outstanding Notes for exchange. Outstanding
Notes that are not tendered or are tendered but not accepted will, following
the consummation of the Exchange Offer, continue to be subject to the existing
restrictions on transfer thereof. On consummation of the Exchange Offer, the
registration rights under the Registration Agreement will terminate except
that if (i) the Company determines that the Exchange Offer may not be
consummated as soon as practicable after the Expiration Date because it would
violate applicable law or the applicable interpretations of the staff of the
Commission, (ii) the Exchange Offer is not consummated within 210 days of the
date of the Registration Agreement, (iii) the Placement Agents so request with
respect to the Outstanding Notes not eligible to be exchanged for Exchange
Notes in the Exchange Offer and held by them
 
                                      22
<PAGE>
 
following consummation of the Exchange Offer or (iv) any holder of an
Outstanding Note (other than an Exchanging Dealer) is not eligible to
participate in the Exchange Offer or, in the case of any holder of Outstanding
Notes (other than an Exchanging Dealer) that participates in the Exchange
Offer, the holder does not receive freely tradeable Exchange Notes on the date
of the exchange for validly tendered (and not withdrawn) Notes, the Company
has agreed to file and maintain a shelf registration statement that would
allow resales of transfer restricted Outstanding Notes or Exchange Notes owned
by the holders. In addition, any holder of Outstanding Notes who tenders in
the Exchange Offer for the purpose of participating in a distribution of the
Exchange Notes may be deemed to have received restricted securities and, if
so, will be required to comply with the registration and prospectus delivery
requirements of the Securities Act in connection with any resale transaction.
Each broker-dealer that receives Exchange Notes for its own account in
exchange for Outstanding Notes, where the Outstanding Notes were acquired by
the broker-dealer as a result of market-making activities or other trading
activities, must acknowledge that it will deliver a prospectus in connection
with any resale of those Exchange Notes. See "Plan of Distribution". To the
extent that Outstanding Notes are tendered and accepted in the Exchange Offer,
the trading market for untendered and tendered but unaccepted Outstanding
Notes could be adversely affected. See "The Exchange Offer".
 
CONSEQUENCES OF THE EXCHANGE OFFER ON NON-TENDERING HOLDERS OF OUTSTANDING
NOTES
 
  The Company intends for the Exchange Offer to satisfy its registration
obligations under the Registration Agreement. If the Exchange Offer is
consummated, the Company does not, except in very limited circumstances set
forth in the Registration Agreement, intend to file further registration
statements for the sale or other disposition of Outstanding Notes.
Consequently, following completion of the Exchange Offer, holders of
Outstanding Notes seeking liquidity in their investment would have to rely on
an exemption to the registration requirements under applicable securities
laws, including the Securities Act, with respect to any sale or other
disposition of Outstanding Notes.
 
                                      23
<PAGE>
 
                              THE EXCHANGE OFFER
 
PURPOSE AND EFFECT OF THE EXCHANGE OFFER
 
  The Outstanding Notes were sold by the Company on October 29, 1996, to the
Placement Agents pursuant to the Placement Agreement. The Placement Agents
subsequently resold the Outstanding Notes to qualified institutional buyers in
reliance on Rule 144A under the Securities Act. In conjunction with the
Placement Agreement, the Company entered into the Registration Agreement with
the Placement Agents, which requires, among other things, that the Company
file with the Commission a registration statement under the Securities Act
with respect to an offer by the Company to the holders of the Outstanding
Notes ("Holders") to issue and deliver to the Holders, in exchange for
Outstanding Notes, a like principal amount of Exchange Notes. The Registration
Agreement obligates the Company to use its best efforts to cause the
registration statement relating to the Exchange Offer to be declared effective
by the Commission under the Securities Act, to commence the Exchange Offer and
to issue and deliver the Exchange Notes to Holders. The Exchange Notes are to
be issued without a restrictive legend and may be reoffered and resold by the
holder without restrictions or limitations under the Securities Act (other
than any holder that is an "affiliate" of the Company within the meaning of
Rule 405 under the Securities Act). A copy of the Registration Agreement has
been filed as an exhibit to the Registration Statement of which this
Prospectus is a part. The term "Holder" with respect to the Exchange Offer
means any person in whose name the Outstanding Notes are registered on the
books of the Company or any other person who has obtained a properly completed
bond power from the registered holder.
 
  Each broker-dealer that receives Exchange Notes for its own account in
exchange for Outstanding Notes, where the Outstanding Notes were acquired by
the broker-dealer as a result of market-making activities or other trading
activities, must acknowledge that it will deliver a prospectus in connection
with any resale of Exchange Notes. See "Plan of Distribution".
 
TERMS OF THE EXCHANGE OFFER
 
  On the terms and subject to the conditions set forth in this Prospectus and
in the Letter of Transmittal, the Company will accept any and all Outstanding
Notes validly tendered and not withdrawn before 12:00 midnight, New York City
time, on the Expiration Date. As soon as practicable after the Expiration
Date, the Company will issue $1,000 principal amount of Exchange Notes in
exchange for $1,000 principal amount of Outstanding Notes accepted in the
Exchange Offer. Holders may tender some or all of their Outstanding Notes
pursuant to the Exchange Offer. However, Outstanding Notes may be tendered
only in integral multiples of $1,000.
 
  The form and terms of the Exchange Notes are the same as the form and terms
of the Outstanding Notes except that (i) the Exchange Notes have been
registered under the Securities Act and will not bear legends restricting the
transfer thereof and (ii) the holders of the Exchange Notes will not be
entitled to certain rights under the Registration Agreement. The Exchange
Notes will evidence the same debt as the Outstanding Notes and will be
entitled to the benefits of the Indenture.
 
  As of the date of this Prospectus, $125,000,000 aggregate principal amount
of the Outstanding Notes was outstanding and registered in the name of Cede &
Co., as nominee for the Depository Trust Company. The Company has fixed the
close of business of          , 1997, as the record date for the Exchange
Offer for purposes of determining the persons to whom this Prospectus and the
Letter of Transmittal will be mailed initially.
 
  Holders of Outstanding Notes do not have any appraisal or dissenters' rights
under the General Corporation Law of Delaware or the Indenture in connection
with the Exchange Offer. The Company intends to conduct the Exchange Offer in
accordance with the applicable requirements of the Exchange Act and the rules
and regulations of the Commission thereunder, including Rule 14e-1 thereunder.
 
 
                                      24
<PAGE>
 
  The Company shall be deemed to have accepted validly tendered Outstanding
Notes when, as and if the Company has given oral or written notice thereof to
the Exchange Agent. The Exchange Agent will act as agent for the tendering
Holders for the purpose of receiving the Exchange Notes from the Company.
 
  If any tendered Outstanding Notes are not accepted for exchange because of
an invalid tender, the occurrence of certain other events set forth herein or
otherwise, the certificates for those unaccepted Outstanding Notes will be
returned, without expense, to the tendering Holder thereof as promptly as
practicable after the Expiration Date.
 
  Holders who tender Outstanding Notes in the Exchange Offer will not be
required to pay brokerage commissions or fees or, subject to the instructions
in the Letter of Transmittal, transfer taxes with respect to the exchange of
Outstanding Notes pursuant to the Exchange Offer. The Company will pay all
charges and expenses, other than transfer taxes in certain circumstances, in
connection with the Exchange Offer. See "--Fees and Expenses".
 
EXPIRATION DATE; EXTENSIONS; AMENDMENTS
 
  The term "Expiration Date" shall mean 12:00 midnight New York City time, on
      , 1997, unless the Company, in its sole discretion, extends the Exchange
Offer, in which case the term "Expiration Date" shall mean the latest date and
time to which the Exchange Offer is extended.
 
  To extend the Exchange Offer, the Company will notify the Exchange Agent of
any extension by oral or written notice and issue a notice of such extention
by press release or other public announcement, each before 9:00 a.m., New York
City time, on the next business day after the previously scheduled expiration
date.
 
  The Company reserves the right, in its sole discretion, (i) to delay
accepting any Outstanding Notes, to extend the Exchange Offer or to terminate
the Exchange Offer if any of the conditions set forth below under
"--Conditions" shall not have been satisfied, by giving oral or written notice
of the delay, extension or termination to the Exchange Agent or (ii) to amend
the terms of the Exchange Offer in any manner. Any such delay in acceptance,
extension, termination or amendment will be followed as promptly as practicable
by oral or written notice thereof to the registered holders. If the Exchange
Offer is amended in a manner determined by the Company to constitute a material
change, the Company will promptly disclose the amendment by means of a
prospectus supplement that will be distributed to the registered Holders, and,
depending on the significance of the amendment and the manner of disclosure to
the registered Holders, the Company will extend the Exchange Offer for a period
of five to 10 business days if the Exchange Offer would otherwise expire during
that five to 10 business day period.
 
  Without limiting the manner in which the Company may choose to make public
announcement of any delay, extension, amendment or termination of the Exchange
Offer, the Company shall have no obligation to publish, advertise or otherwise
communicate any such public announcement, other than by making a timely
release to the Dow Jones News Service.
 
INTEREST ON THE EXCHANGE NOTES
 
  The Exchange Notes will bear interest from the date of issuance of the
Exchange Notes. Interest on the Exchange Notes will be payable semiannually on
each April 15 and October 15, commencing on the first such date following the
date of issuance of the Exchange Notes. Outstanding Notes that are accepted
for exchange will cease to accrue interest on and after the date on which
interest on the Exchange Notes begins to accrue. Accrued and unpaid interest
on the Outstanding Notes that are tendered in exchange for the Exchange Notes
will be payable on or before the first April 15 or October 15 following the
date of issuance of the Exchange Notes.
 
PROCEDURES FOR TENDERING
 
  Only a Holder of Outstanding Notes may tender those Outstanding Notes in the
Exchange Offer. To tender in the Exchange Offer, a Holder must complete, sign
and date the Letter of Transmittal, or a facsimile thereof,
 
                                      25
<PAGE>
 
have the signatures thereon guaranteed if required by the Letter of
Transmittal and mail or otherwise deliver the Letter of Transmittal or the
facsimile, together with the Outstanding Notes and any other required
documents, to the Exchange Agent before 12:00 midnight, New York City time, on
the Expiration Date. To be tendered effectively, the Outstanding Notes, Letter
of Transmittal and other required documents must be received by the Exchange
Agent at the address set forth below under "Exchange Agent" before 12:00
midnight, New York City time, on the Expiration Date. Delivery of the
Outstanding Notes may be made by book-entry transfer in accordance with the
procedures described below. Confirmation of book-entry transfer must be received
by the Exchange Agent before the Expiration Date.
 
  By executing the Letter of Transmittal, each Holder will make to the Company
the representation set forth below in the second paragraph under the heading
"Resale of Exchange Notes".
 
  The tender by a Holder and the acceptance thereof by the Company will
constitute agreement between the Holder and the Company in accordance with the
terms and subject to the conditions set forth herein and in the Letter of
Transmittal.
 
  THE METHOD OF DELIVERY OF OUTSTANDING NOTES AND THE LETTER OF TRANSMITTAL
AND ALL OTHER REQUIRED DOCUMENTS TO THE EXCHANGE AGENT IS AT THE ELECTION AND
RISK OF THE HOLDER. INSTEAD OF DELIVERY BY MAIL, IT IS RECOMMENDED THAT
HOLDERS USE AN OVERNIGHT OR HAND DELIVERY SERVICE. IN ALL CASES, SUFFICIENT
TIME SHOULD BE ALLOWED TO ASSURE DELIVERY TO THE EXCHANGE AGENT BEFORE THE
EXPIRATION DATE. NO LETTER OF TRANSMITTAL OR OUTSTANDING NOTES SHOULD BE SENT
TO THE COMPANY. HOLDERS MAY REQUEST THEIR RESPECTIVE BROKERS, DEALERS,
COMMERCIAL BANKS, TRUST COMPANIES OR NOMINEES TO EFFECT THE ABOVE TRANSACTIONS
FOR THEM.
 
  Any beneficial owner whose Outstanding Notes are registered in the name of a
broker, dealer, commercial bank, trust company or other nominee and who wishes
to tender should contact the registered Holder promptly and instruct the
registered Holder to tender on it's behalf.
 
  Signatures on the Letter of Transmittal or a notice of withdrawal, as the
case may be, must be guaranteed by an Eligible Institution (as defined below)
unless the Outstanding Notes tendered pursuant thereto are tendered (i) by a
registered Holder who has not completed the box entitled "Special Registration
Instructions" or "Special Delivery Instructions" on the Letter of Transmittal
or (ii) for the account of an Eligible Institution. In the event that
signatures on a Letter of Transmittal or a notice of withdrawal, as the case
may be, are required to be guaranteed, the guarantee must be by a member firm
of a registered national securities exchange or of the National Association of
Securities Dealers, Inc., a commercial bank or trust company having an office
or correspondent in the United States or an "eligible guarantor institution"
within the meaning of Rule 17Ad-15 under the Exchange Act (an "Eligible
Institution").
 
  If the Letter of Transmittal is signed by a person other than the registered
Holder of any Outstanding Notes listed therein, those Outstanding Notes must
be endorsed or accompanied by a properly completed bond power, signed by the
registered Holder as the registered Holder's name appears on the Outstanding
Notes with the signature thereon guaranteed by an Eligible Institution.
 
  If the Letter of Transmittal or any Outstanding Notes or bond powers are
signed by trustees, executors, administrators, guardians, attorneys-in-fact,
officers of corporations or others acting in a fiduciary or representative
capacity, those persons should so indicate when signing, and unless waived by
the Company, evidence satisfactory to the Company of their authority to so act
must be submitted with the Letter of Transmittal.
 
  The Company understands that the Exchange Agent will make a request promptly
after the date of this Prospectus to establish accounts with respect to the
Exchange Notes at the DTC (the "Book-Entry Transfer Facility") for the purpose
of facilitating the Exchange Offer, and subject to the establishment thereof,
any financial institution that is a participant in the Book-Entry Transfer
Facility's system may make book-entry
 
                                      26
<PAGE>
 
delivery of the Outstanding Notes by causing the Book-Entry Transfer Facility
to transfer the Outstanding Notes into the Exchange Agent's account with
respect to the Outstanding Notes in accordance with the Book-Entry Transfer
Facility's procedures for transfer. Although delivery of the Outstanding Notes
may be effected through book-entry transfer into the Exchange Agent's account at
the Book-Entry Transfer Facility, an appropriate Letter of Transmittal properly
completed and duly executed with any required signature guarantee and all other
required documents must in each case be transmitted to and received or confirmed
by the Exchange Agent at its address set forth below on or before the Expiration
Date, or, if the guaranteed delivery procedures described below are complied
with, within the time period provided under those procedures; provided, however,
that a participant in DTC's book-entry system may, in accordance with DTC's
Automated Tender Offer Program procedures and in lieu of physical delivery to
the Exchange Agent of a Letter of Transmittal, electronically acknowledge its
receipt of, and agreement to be bound by, the terms of the Letter of
Transmittal. Delivery of documents to the Book-Entry Transfer Facility does not
constitute delivery to the Exchange Agent.
 
  All questions as to the validity, form, eligibility (including time of
receipt), acceptance and withdrawal of tendered Outstanding Notes will be
determined by the Company in its sole discretion, which determination will be
final and binding. The Company reserves the absolute right to reject any and
all Outstanding Notes not properly tendered or any Outstanding Notes the
Company's acceptance of which would, in the opinion of counsel for the
Company, be unlawful. The Company also reserves the right to waive any
defects, irregularities or conditions of tender as to particular Outstanding
Notes. The Company's interpretation of the terms and conditions of the
Exchange Offer (including the instructions in the Letter of Transmittal) will
be final and binding on all parties. Unless waived, any defects or
irregularities in connection with tenders of Outstanding Notes must be cured
within such time as the Company shall determine. Although the Company intends
to notify Holders of defects or irregularities with respect to tenders of
Outstanding Notes, neither the Company, the Exchange Agent nor any other
person shall incur any liability for failure to give such notification.
Tenders of Outstanding Notes will not be deemed to have been made until all
defects or irregularities have been cured or waived. Any Outstanding Notes
received by the Exchange Agent that are not properly tendered and as to which
the defects or irregularities have not been cured or waived will be returned
by the Exchange Agent to the tendering Holders, unless otherwise provided in
the Letter of Transmittal, as soon as practicable following the Expiration
Date.
 
  Each broker-dealer that receives Exchange Notes for its own account in
exchange for Outstanding Notes, where the Outstanding Notes were acquired by
the broker-dealer as a result of market-making activities or other trading
activities, must acknowledge that it will deliver a prospectus in connection
with any resale of Exchange Notes. See "Plan of Distribution".
 
GUARANTEED DELIVERY PROCEDURES
 
  Holders who wish to tender their Outstanding Notes and (i) whose Outstanding
Notes are not immediately available, (ii) who cannot deliver their Outstanding
Notes, the Letter of Transmittal or any other required documents to the
Exchange Agent or (iii) who cannot complete the procedures for book-entry
transfer, before the Expiration Date, may effect a tender if:
 
    (a) the tender is made through an Eligible Institution;
 
    (b) before the Expiration Date, the Exchange Agent receives from the
  Eligible Institution a properly completed and duly executed Notice of
  Guaranteed Delivery (by facsimile transmission, mail or hand delivery)
  setting forth the name and address of the Holder, the certificate number(s)
  of the Outstanding Notes and the principal amount of Outstanding Notes
  tendered, stating that the tender is being made thereby and guaranteeing
  that, within five New York Stock Exchange trading days after the Expiration
  Date, the Letter of Transmittal (or facsimile thereof), together with the
  certificate(s) representing the Outstanding Notes (or a confirmation of
  book-entry transfer of those Outstanding Notes into the Exchange Agent's
  account at the Book-Entry Transfer Facility) and any other documents
  required by the Letter of Transmittal, will be deposited by the Eligible
  Institution with the Exchange Agent; and
 
 
                                      27
<PAGE>
 
    (c) the properly completed and executed Letter of Transmittal (or
  facsimile thereof), as well as the certificate(s) representing all tendered
  Outstanding Notes in proper form for transfer (or a confirmation of book-
  entry transfer of those Outstanding Notes into the Exchange Agent's account
  at the Book-Entry Transfer Facility) and all other documents required by
  the Letter of Transmittal, are received by the Exchange Agent within five
  New York Stock Exchange trading days after the Expiration Date.
 
  On request to the Exchange Agent, a Notice of Guaranteed Delivery will be
sent to Holders who wish to tender their Outstanding Notes according to the
guaranteed delivery procedures set forth above.
 
WITHDRAWALS OF TENDERS
 
  Except as otherwise provided herein, tenders of Outstanding Notes may be
withdrawn at any time before 12:00 midnight, New York City time, on the
Expiration Date.
 
  To withdraw a tender of Outstanding Notes in the Exchange Offer, a written
or facsimile transmission notice of withdrawal must be received by the
Exchange Agent at its address set forth herein before 12:00 midnight, New York
City time, on the Expiration Date. Any such notice of withdrawal must (i)
specify the name of the person having deposited the Outstanding Notes to be
withdrawn (the "Depositor"), (ii) identify the Outstanding Notes to be
withdrawn (including the certificate number(s) and principal amount of the
Outstanding Notes, or, in the case of Outstanding Notes transferred by book-
entry transfer, the name and number of the account at the Book-Entry Transfer
Facility to be credited), (iii) be signed by the Holder in the same manner as
the original signature on the Letter of Transmittal by which the Outstanding
Notes were tendered (including any required signature guarantees) or be
accompanied by documents of transfer sufficient to have the Trustee with
respect to the Outstanding Notes register the transfer of those Outstanding
Notes in the name of the person withdrawing the tender, (iv) specify the name
in which any such Outstanding Notes are to be registered, if different from
that of the Depositor and (v) if applicable because the Outstanding Notes have
been tendered pursuant to book-entry procedures, specify the name and number
of the participant's account at DTC to be credited, if different from that of
the Depositor. All questions as to the validity, form and eligibility
(including time of receipt) of such notices will be determined by the Company,
whose determination shall be final and binding on all parties. Any Outstanding
Notes so withdrawn will be deemed not to have been validly tendered for
purposes of the Exchange Offer and no Exchange Notes will be issued with
respect thereto unless the Outstanding Notes so withdrawn are validly
retendered. Any Outstanding Notes that have been tendered but that are not
accepted for exchange, will be returned to the Holder thereof without cost to
the Holder as soon as practicable after withdrawal, rejection of tender or
termination of the Exchange Offer. Properly withdrawn Outstanding Notes may be
retendered by following one of the procedures described above under
"--Procedures for Tendering" at any time before the Expiration Date.
 
CONDITIONS
 
  Notwithstanding any other term of the Exchange Offer, the Company shall not
be required to accept for exchange, or to issue Exchange Notes for, any
Outstanding Notes, and may terminate or amend the Exchange Offer as provided
herein before the acceptance of any Outstanding Notes, if:
 
    (a) any action or proceeding is instituted or threatened in any court or
  by or before any governmental agency with respect to the Exchange Offer
  that might materially impair the ability of the Company to proceed with the
  Exchange Offer or any material adverse development has occurred in any
  existing action or proceeding with respect to the Company or any of its
  subsidiaries;
 
    (b) any change, or any development involving a prospective change, in the
  business or financial affairs of the Company or any of its subsidiaries has
  occurred that might materially impair the ability of the Company to proceed
  with the Exchange Offer;
 
 
                                      28
<PAGE>
 
    (c) any law, statute, rule, regulation or interpretation by the staff of
  the Commission is proposed, adopted or enacted that might materially impair
  the ability of the Company to proceed with the Exchange Offer or materially
  impair the contemplated benefits of the Exchange Offer to the Company;
 
    (d) there shall occur a change in the current interpretation by the staff
  of the Commission that permits the Exchange Notes issued pursuant to the
  Exchange Offer in exchange for Outstanding Notes to be offered for resale,
  resold and otherwise transferred by Holders thereof (other than broker-
  dealers and any Holder that is an "affiliate" of the Company within the
  meaning of Rule 405 under the Securities Act) without compliance with the
  registration and prospectus delivery provisions of the Securities Act;
  provided that the Exchange Notes are acquired in the ordinary course of the
  Holders' business and the Holders have no arrangement or understanding with
  any person to participate in the distribution of the Exchange Notes; or
 
    (e) any governmental approval has not been obtained, which approval the
  Company shall deem necessary for the consummation of the Exchange Offer as
  contemplated hereby.
 
  If the Company determines in good faith and in the exercise of its
reasonable discretion that any of the conditions are not satisfied, the
Company may (i) refuse to accept any Outstanding Notes and return all tendered
Outstanding Notes to the tendering Holders, (ii) extend the Exchange Offer and
retain all Outstanding Notes tendered before the expiration of the Exchange
Offer, subject, however, to the rights of Holders to withdraw tenders of
Outstanding Notes (see "--Withdrawal of Tenders") or (iii) waive the
unsatisfied conditions with respect to the Exchange Offer and accept all
properly tendered Outstanding Notes which have not been withdrawn. If such
waiver constitutes a material change to the Exchange Offer, the Company will
promptly disclose the waiver by means of a prospectus supplement that will be
distributed to the registered Holders, and, depending on the significance of
the waiver and the manner of disclosure to the registered Holders, the Company
will extend the Exchange Offer for a period of five to 10 business days if the
Exchange Offer would otherwise expire during that five to 10 day period.
 
EXCHANGE AGENT
 
  United States Trust Company of New York has been appointed as Exchange Agent
for the Exchange Offer. Questions and requests for assistance, requests for
additional copies of his Prospectus or of the Letter of Transmittal and
requests for Notice of Guaranteed Delivery should be directed to the Exchange
Agent addressed as follows:
 
     By Hand Delivery:       By Overnight Courier:           By Mail:
 
                                 770 Broadway
       111 Broadway               13th Floor                  Box 843
        Lower Level           New York, NY 10003       Peter Cooper Station
    New York, NY 10005   Attn: Corporate Trust Service  New York, NY 10276
   Attn: Corporate Trust            Window             Attn: Corporate Trust
 
      By Facsimile Transmission:                  For Information:
 
 
   (For Eligible Institutions Only)                (800) 548-6565
            (212) 420-6152
         Confirm by Telephone:
            (800) 548-6565
 
FEES AND EXPENSES
 
  The expenses of soliciting tenders pursuant to the Exchange Offer will be
borne by the Company. The principal solicitation is being made by mail;
however, additional solicitation may be made by telegraph, telephone or in
person by officers and regular employees of the Company and its affiliates.
 
 
                                      29
<PAGE>
 
  The Company has not retained any dealer-manager in connection with the
Exchange Offer and will not make any payments to brokers or other soliciting
acceptances of the Exchange Offer. The Company, however, will pay the Exchange
Agent reasonable and customary fees for its services and registration
expenses, including fees and expenses of the Trustee, filing fees, blue sky
fees and printing and distribution expenses.
 
  The Company will pay all transfer taxes, if any, applicable to the exchange
of the Outstanding Notes pursuant to the Exchange Offer. If, however,
certificates representing the Exchange Notes or the Outstanding Notes for the
principal amounts not tendered or accepted for exchange are to be delivered
to, or are to be issued in the name of, any person other than the person signing
the Letter of Transmittal, or if a transfer tax is imposed for any reason other
than the exchange of the Outstanding Notes pursuant to the Exchange Offer, then
the amount of that transfer tax (whether imposed on the registered Holder or any
other person) will be payable by the tendering Holder.
 
ACCOUNTING TREATMENT
 
  The Exchange Notes will be recorded at the same carrying value as the
Outstanding Notes, which is face value as adjusted for original issue
discount, as reflected in the Company's accounting records on the date of
exchange. Accordingly, no gain or loss for accounting purposes will be
recognized. The expenses of the Exchange Offer will be amortized over the term
of the Exchange Notes.
 
RESALE OF EXCHANGE NOTES
 
  The Company has not requested, and does not intend to request, an
interpretation by the staff of the Commission with respect to whether the
Exchange Notes issued in the Exchange Offer in exchange for the Outstanding
Notes may be offered for sale, resold or otherwise transferred by any holder
thereof without compliance with the registration and prospectus delivery
requirements of the Securities Act. Based on an interpretation by the staff of
the Commission set forth in no-action letters issued to third parties, the
Company believes that Exchange Notes issued pursuant to the Exchange Offer in
exchange for Outstanding Notes may be offered for resale, resold and otherwise
transferred by any holder of Exchange Notes (other than any holder that is an
"affiliate" of the Company within the meaning of Rule 405 under the Securities
Act) without compliance with the registration and prospectus delivery
provisions of the Securities Act, provided that the Exchange Notes are
acquired in the ordinary course of the holder's business and the holder does
not intend to participate and has no arrangement or understanding with any
person to participate in the distribution of the Exchange Notes. Any holder
who tenders in the Exchange Offer with the intention to participate, or for
the purpose of participating, in a distribution of the Exchange Notes may not
rely on the position of the staff of the Commission enunciated in Exxon
Capital Holdings Corporation (available April 13, 1989) and Morgan Stanley &
Co., Incorporated (June 5, 1991), or similar no-action letters, but rather
must comply with the registration and prospectus delivery requirements of the
Securities Act in connection with any resale transaction. In addition, any
such resale transaction should be covered by an effective registration
statement containing the selling security holders information required by Item
507 of Regulation S-K of the Securities Act.
 
  Each broker-dealer that receives Exchange Notes for its own account in
exchange for Outstanding Notes, where the Outstanding Notes were acquired by
the broker-dealer as a result of market-making activities or other trading
activities, must acknowledge that it will deliver a prospectus in connection
with any resale of Exchange Notes. See "Plan of Distribution".
 
  By tendering in the Exchange Offer, each Holder will represent to the
Company that, among other things, (i) the Exchange Notes acquired pursuant to
the Exchange Offer are being obtained in the ordinary course of business of
the person receiving the Exchange Notes, whether or not that person is a
Holder, (ii) neither the Holder nor any such other person has an arrangement
or understanding with any person to participate in the distribution of the
Exchange Notes and (iii) the Holder and such other person acknowledge that if
they participate in the Exchange Offer for the purpose of distributing the
Exchange Notes (a) they must, in the absence of an exemption therefrom, comply
with the registration and prospectus delivery requirements of the Securities
Act in
 
                                      30
<PAGE>
 
connection with any resale of the Exchange Notes and cannot rely on the no-
action letters referenced above and (b) failure to comply with those
requirements in such instance could result in the Holder incurring liability
under the Securities Act for which the Holder is not indemnified by the
Company. Further, by tendering in the Exchange Offer, each Holder that may be
deemed an "affiliate" (as defined under Rule 405 of the Securities Act) of the
Company will represent to the Company that the Holder understands and
acknowledges that the Exchange Notes may not be offered for resale, resold or
otherwise transferred by that Holder without registration under the Securities
Act or an exemption therefrom.
 
  As set forth above, affiliates of the Company are not entitled to rely on
the foregoing interpretations of the staff of the Commission with respect to
resales of the Exchange Notes without compliance with the registration and
prospectus delivery requirements of the Securities Act.
 
CONSEQUENCES OF FAILURE TO EXCHANGE
 
  As a result of the making of this Exchange Offer, the Company will have
fulfilled one of its obligations under the Registration Agreement, and, except
as described under "--Shelf Registration Statement", Holders of Outstanding
Notes who do not tender their Outstanding Notes will not have any further
registration rights under the Registration Agreement or otherwise.
Accordingly, any Holder of Outstanding Notes that does not exchange its
Outstanding Notes for Exchange Notes will continue to hold the untendered
Outstanding Notes and will be entitled to all the rights and limitations
applicable thereto under the Indenture, except to the extent those rights or
limitations that, by their terms, terminate or cease to have further
effectiveness as a result of the Exchange Offer.
 
  The Outstanding Notes that are not exchanged for Exchange Notes pursuant to
the Exchange Offer will remain restricted securities. Accordingly, such
Outstanding Notes may be resold only (i) to the Company (on redemption thereof
or otherwise), (ii) pursuant to an effective registration statement under the
Securities Act, (iii) so long as the Outstanding Notes are eligible for resale
pursuant to Rule 144A, to a qualified institutional buyer within the meaning
of Rule 144A under the Securities Act in a transaction meeting the
requirements of Rule 144A, (iv) outside the United States to a foreign person
pursuant to the exemption from the registration requirements of the Securities
Act provided by Regulation S thereunder, (v) to an institutional accredited
investor that, before the transfer, furnishes to United States Trust Company
of New York, as trustee, a signed letter containing certain representations
and agreements relating to the restrictions on transfer of the Outstanding
Notes evidenced thereby (the form of which letter can be obtained from the
Trustee) or (vi) pursuant to another available exemption from the registration
requirements of the Securities Act, in each case in accordance with any
applicable securities laws of any state of the United States.
 
  Accordingly, to the extent that Outstanding Notes are tendered and accepted
in the Exchange Offer, the trading market for the untendered Outstanding Notes
could be adversely affected.
 
SHELF REGISTRATION STATEMENT
 
  If (i) the Company determines that the Exchange Offer may not be consummated
as soon as practicable after the Expiration Date because it would violate
applicable law or the applicable interpretations of the staff of the
Commission, (ii) the Exchange Offer is not consummated within 210 days of the
date of the Registration Agreement, (iii) the Placement Agents so request with
respect to the Outstanding Notes not eligible to be exchanged for Exchange
Notes in the Exchange Offer and held by them following consummation of the
Exchange Offer or (iv) any holder of an Outstanding Note (other than an
Exchanging Dealer) is not eligible to participate in the Exchange Offer or, in
the case of any holder of Outstanding Notes (other than an Exchanging Dealer)
that participates in the Exchange Offer, the holder does not receive freely
tradeable Exchange Notes on the date of the exchange for validly tendered (and
not withdrawn) Notes, the Company has agreed to file and maintain a shelf
registration statement that would allow resales of transfer restricted
Outstanding Notes or Exchange Notes owned by those holders.
 
 
                                      31
<PAGE>
 
OTHER
 
  Participation in the Exchange Offer is voluntary and holders should
carefully consider whether to accept. Holders of the Outstanding Notes are
urged to consult their financial and tax advisors in making their own decision
on what action to take.
 
  No person has been authorized to give any information or to make any
representations in connection with the Exchange Offer other than those
contained in this Prospectus. If given or made, such information or
representations should not be relied on as having been authorized by the
Company. Neither the delivery of this Prospectus nor any exchange made
hereunder shall, under any circumstances, create any implication that there
has been no change in the affairs of the Company since the respective dates as
of which information is given herein. The Exchange Offer is not being made to
(nor will tender be accepted from or, on behalf of) holders of Outstanding
Notes in any jurisdiction in which the making of the Exchange Offer or the
acceptance thereof would not be in compliance with the laws of that
jurisdiction. However, the Company may, at its discretion, take such action as
it may deem necessary to make the Exchange Offer in that jurisdiction and
extend the Exchange Offer to holders of Outstanding Notes in that
jurisdiction. In any jurisdiction the securities laws or blue sky laws of
which require the Exchange Offer to be made by a licensed broker or dealer,
the Exchange Offer is being made on behalf of the Company by one or more
registered brokers or dealers which are licensed under the laws of that
jurisdiction.
 
  The Company may in the future seek to acquire untendered Outstanding Notes
in open market or privately negotiated transactions, through subsequent
exchange offers or otherwise. The Company has no present plans to acquire any
Outstanding Notes that are not tendered in the Exchange Offer or to file a
registration statement to permit resales of any untendered Outstanding Notes,
except for the filing, if required, of the Shelf Registration Statement.
 
                                      32
<PAGE>
 
                                USE OF PROCEEDS
 
  This Exchange Offer is intended to satisfy certain of the Company's
obligations under the Purchase Agreement and the Registration Agreement. The
Company will not receive any cash proceeds from the issuance of the Exchange
Notes offered hereby. In consideration for issuing the Exchange Notes
contemplated in this Prospectus, the Company will receive Outstanding Notes in
like principal amount, the form and terms of which are the same as the form
and terms of the Exchange Notes (which they replace), except as otherwise
described herein. The Outstanding Notes surrendered in exchange for Exchange
Notes will be retired and canceled and cannot be reissued. Accordingly,
issuance of the Exchange Notes will not result in any increase or decrease in
the indebtedness of the Company.
 
  The net proceeds of the Note Offering were approximately $119.8 million. The
Company used substantially all of these proceeds to pay the Tender Offer
Consideration to holders of the 13 1/2% Notes that were validly tendered and
accepted for payment pursuant to the Tender Offer and to pay Consent Payments
to holders of the 13 1/2% Notes who validly consented pursuant to the
Solicitation.
 
                                      33
<PAGE>
 
                                CAPITALIZATION
 
  The following table sets forth the actual capitalization of the Company as
of September 30, 1996, and the as adjusted capitalization of the Company as of
such date to give effect to the Refinancing.
 
<TABLE>
<CAPTION>
                                                              AS OF SEPTEMBER
                                                                 30, 1996
                                                             ------------------
                                                                          AS
                                                              ACTUAL   ADJUSTED
                                                             --------  --------
                                                              (IN THOUSANDS)
                                                                (UNAUDITED)
<S>                                                          <C>       <C>
LONG-TERM DEBT:
  Bank debt(1).............................................. $  7,000   $ 7,000
  13 1/2% Senior Notes due 1999.............................   96,796       435
  10 3/8% Senior Subordinated Notes Due 2006................       --   119,788
  8 1/2% Convertible Subordinated Debentures due 2000.......   22,605    22,605
  7 7/8% Convertible Subordinated Notes due 1999............   26,948    26,948
                                                             --------  --------
    Total long-term debt....................................  153,349   176,776
                                                             --------  --------
STOCKHOLDERS' DEFICIT:
  Convertible Exchangeable Preferred Stock..................    2,618     2,618
  Common Stock..............................................      983       983
  Additional paid-in capital................................  273,088   273,088
  Retained deficit(2)....................................... (290,524) (307,650)
                                                             --------  --------
    Total stockholders' deficit.............................  (13,835)  (30,961)
                                                             --------  --------
      Total capitalization.................................. $139,514  $145,815
                                                             ========  ========
</TABLE>
--------
(1) The borrowing base under the New Credit Facility currently is $57.5
    million. See "Management's Discussion and Analysis of Financial Condition
    and Results of Operations--Liquidity and Capital Resources".
(2) Includes an extraordinary loss of $17.1 million related to the excess of
    the aggregate purchase price of the 13 1/2% Notes (including Consent
    Payments) over the carrying value of the 13 1/2% Notes as of September 30,
    1996.
 
                                      34
<PAGE>
 
                     SELECTED CONSOLIDATED FINANCIAL DATA
 
 
  The following tables present selected historical and unaudited pro forma
financial data for the Company. The historical financial information as of and
for the years ended December 31 in each of the four years presented through
1994 is derived from the audited consolidated financial statements of Kelley
Oil. The Consolidation was treated as a purchase of interests in Kelley
Partners by the Company for financial accounting purposes. Accordingly, the
historical financial information for the year ended December 31, 1995,
reflects Kelley Oil's historical results on a stand-alone basis through the
date of the Consolidation in February 1995, with the results of combined
operations recorded thereafter. The unaudited financial information as of
September 30, 1996, and for the nine months ended September 30, 1996 and 1995
has been prepared by the Company in accordance with generally accepted
accounting principles and reflects all adjustments (consisting of normal
recurring adjustments) necessary for a fair statement in all material respects
of the results for the interim periods presented. Certain financial statement
items in the interim 1995 period have been reclassified to conform to the
interim 1996 presentation. This information should be read in conjunction with
"Capitalization", "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and the Consolidated Financial Statements of the
Company included elsewhere in this Prospectus. The pro forma financial
information presented below is unaudited and gives effect to the Consolidation
as of January 1, 1994. The pro forma financial information does not purport to
represent what the Company's results of operations actually would have been
had the Consolidation occurred on such date or to project the Company's
results of operations for any future period.
 
<TABLE>
<CAPTION>
                                                                                              NINE MONTHS ENDED
                                       YEAR ENDED DECEMBER 31,                                  SEPTEMBER 30,
                    --------------------------------------------------------------------  ----------------------------
                     1991     1992      1993      1994      1995       1994      1995       1995      1995      1996
                    -------  -------  --------  --------  ---------  --------  ---------  --------  --------  --------
                                                                       PRO        PRO                 PRO
                                                                      FORMA      FORMA               FORMA
                                                                     --------  ---------            --------
                                                         (IN THOUSANDS)
 <S>                <C>      <C>      <C>       <C>       <C>        <C>       <C>        <C>       <C>       <C>
 INCOME STATEMENT
  DATA:
 Oil and gas
  revenues........  $13,179  $18,098  $ 19,711  $ 15,487  $  36,042  $ 42,348  $  38,550  $ 26,284  $ 28,792  $ 40,201
 Gas marketing
  revenues, net...    1,216    1,013     1,353     1,335        956        45        958       677       679     1,078
 Gain on sale of
  oil and gas
  properties......       --       --        --        --        777        --        777       777       777        --
 Other income.....      566      819       710       623        404       742        404       310       310       334
                    -------  -------  --------  --------  ---------  --------  ---------  --------  --------  --------
  Total operating
   revenues.......   14,961   19,930    21,774    17,445     38,179    43,135     40,689    28,048    30,558    41,613
                    -------  -------  --------  --------  ---------  --------  ---------  --------  --------  --------
 Production
  expenses........    2,325    3,478     3,993     3,760     10,835    12,318     11,461     7,739     8,365     7,638
 Exploration
  costs...........    3,012    7,126    14,226     7,404     23,387    18,083     23,727    10,523    10,863     4,216
 General and
  administrative
  expenses........    2,970    3,478     4,079     5,172      7,030     8,308      7,398     4,346     4,714     6,950
 Depreciation,
  depletion and
  amortization....    5,813    9,768    18,857    20,474     35,591    39,727     36,190    23,704    24,303    15,293
 Impairment of oil
  and gas
  properties(1) ..       --       --        --        --    150,138        --    150,138       --        --        --
 Restructuring
  expense.........       --       --        --     1,814      1,115     1,814      1,115       --        --      2,000
                    -------  -------  --------  --------  ---------  --------  ---------  --------  --------  --------
 Operating income
  (loss)..........      841   (3,920)  (19,381)  (21,179)  (189,917)  (37,115)  (189,340)  (18,264)  (17,687)    5,516
 Interest income..      587      567       796       793        582       851        587       417       422       604
 Interest expense
  and other debt
  expenses........      950    2,684     6,638     4,571     21,956    12,361     22,763    15,137    15,944    18,376
                    -------  -------  --------  --------  ---------  --------  ---------  --------  --------  --------
 Income (loss)
  before income
  taxes...........      478   (6,037)  (25,223)  (24,957)  (211,291)  (48,625)  (211,516)  (32,984)  (33,209) (12,256)
 Provision
  (benefit) for
  taxes...........       25   (1,071)       --        --         --        --         --        --        --        --
                    -------  -------  --------  --------  ---------  --------  ---------  --------  --------  --------
 Net income
  (loss)..........      453   (4,966)  (25,223)  (24,957)  (211,291)  (48,625)  (211,516)  (32,984)  (33,209)  (12,256)
                    -------  -------  --------  --------  ---------  --------  ---------  --------  --------  --------
 Less: cumulative
  preferred stock
  dividends.......      770      729       894     2,905      6,607     4,611      7,033     4,867     5,293        --
                    -------  -------  --------  --------  ---------  --------  ---------  --------  --------  --------
 Net loss
  applicable to
  common stock....  $  (317) $(5,695) $(26,117) $(27,862) $(217,898) $(53,236) $(218,549) $(37,851) $(38,502) $(12,256)
                    =======  =======  ========  ========  =========  ========  =========  ========  ========  ========
</TABLE>
 
<TABLE>
<CAPTION>
                                    AS OF DECEMBER 31,                  AS OF
                         -----------------------------------------  SEPTEMBER 30,
                          1991    1992    1993     1994     1995        1996
                         ------- ------- ------- -------- --------  -------------
                                             (IN THOUSANDS)
<S>                      <C>     <C>     <C>     <C>      <C>       <C>
BALANCE SHEET DATA:
Total assets............ $71,308 $95,562 $87,145 $106,513 $151,342    $179,421
Working capital
 (deficit)..............   9,856  15,646   2,622    3,788   (9,233)   (17,062)
Property and equipment,
 net....................  34,568  50,019  58,018   74,912  128,642     155,502
Total long-term debt....  18,272  44,763  34,814   37,242  164,980     153,349
Stockholders' equity
 (deficit)..............  28,297  24,411  27,415   45,180  (45,568)   (13,835)
</TABLE>
-------
(1) Reflects noncash impairment charges against the carrying value of proved
    and unproved properties under FAS 121. See "Management's Discussion and
    Analysis of Financial Condition and Results of Operations" and the
    Consolidated Financial Statements of the Company included elsewhere in
    this Prospectus.
 
                                      35
<PAGE>
 
               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 Prospectus.
 
GENERAL
 
  Kelley is engaged in oil and natural gas exploration, development,
production and acquisition. Kelley's activities are concentrated primarily in
two geographic areas: north Louisiana and south Louisiana. At September 30,
1996, approximately 87% of Kelley's proved reserves are located on 48,620
gross (23,668 net) acres within four fields in Webster and Bienville Parishes
of north Louisiana, where its activities are focused on lower-risk development
drilling. Substantially all of the balance of Kelley's proved reserves are
located in south Louisiana, primarily in Terrebonne Parish. Kelley intends to
continue its primary emphasis on development drilling in its north Louisiana
fields where it believes it has opportunities for production growth. Kelley's
exploration activities will focus on its existing leaseholdings in Terrebonne
Parish, where the Company believes successful wells have the potential for
larger reserves and production as compared to development wells in north
Louisiana. In that regard, Kelley is utilizing advanced geophysical techniques
to re-evaluate and refine interpretations of Kelley's 3-D seismic database and
is pursuing industry partnerships in order to manage the exploration risks
associated with its south Louisiana properties.
 
  Fourth Quarter Extraordinary Loss. In connection with repurchase of the 13
1/2% Notes and the payment of Consent Payments pursuant to the Tender Offer
and the Solicitation, the Company expects to incur an extraordinary loss in
the fourth quarter of 1996 of approximately $17.0 million, representing the
excess of the aggregate purchase price of the 13 1/2% Notes (including Consent
Payments) over their carrying value as of the date of the consummation of the
Refinancing.
 
  Pro Forma Comparison. Because Kelley's historical results for periods prior
to the Consolidation reflect operations of Kelley Oil alone, they are not
comparable with its operating results after February 1995, which reflect
Kelley's combined operations following the Consolidation. Accordingly, the
following discussion of comparative results of operations for the nine months
ended September 30, 1995 and 1996 and the years ended December 31, 1994 and
1995 reflect pro forma information for the first nine months of 1995 and for
both 1994 and 1995, giving effect to the Consolidation from the beginning of
1994. The Company believes this provides a more meaningful comparison of
results and operational trends than a comparison based on historical results.
The discussion of comparative results for the years ended 1993 and 1994
reflects historical financial information for Kelley Oil on a stand-alone
basis. The following table sets forth certain operating data regarding net
production, average sales prices, production expenses and revenues associated
with Kelley's oil and natural gas operations for the periods indicated.
<TABLE>
<CAPTION>
                                                                  NINE MONTHS
                                                                     ENDED
                                      YEAR ENDED DECEMBER 31,    SEPTEMBER 30,
                                    --------------------------- ---------------
                                     1993   1994   1994   1995   1995    1996
                                    ------ ------ ------ ------ ------- -------
                                                   PRO    PRO     PRO
                                                  FORMA  FORMA   FORMA
                                                  ------ ------ -------
<S>                                 <C>    <C>    <C>    <C>    <C>     <C>
NET PRODUCTION DATA:
  Oil and other liquid hydrocarbons
   (Mbbls).........................    202    171    446    348     273     181
  Natural gas (Mmcf)...............  7,327  6,697 18,141 18,828  14,178  16,221
  Natural gas equivalent (Mmcfe)...  8,539  7,723 20,817 20,916  15,813  17,307
AVERAGE SALES PRICE PER UNIT:
  Oil and other liquid hydrocarbons
   (per Bbl)....................... $17.84 $16.31 $16.30 $17.31 $ 17.53 $ 21.29
  Natural gas (per Mcf)............   2.20   1.89   1.87   1.72    1.69    2.27
  Natural gas equivalent (per
   Mcfe)...........................   2.31   2.01   2.03   1.84    1.82    2.35
COST PER MCFE:
  Production expenses..............    .47    .49    .59    .55     .53     .44
  General and administrative
   expenses........................    .48    .67    .40    .35     .30     .40
  Depreciation, depletion and
   amortization....................   2.21   2.65   1.91   1.73    1.54     .88
</TABLE>
 
 
                                      36
<PAGE>
 
  Impairment of Assets. In the fourth quarter of 1995, the Company implemented
the Financial Accounting Standards Board's Statement No. 121, Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of ("FAS 121"). Under FAS 121, certain assets are required to be reviewed
periodically for impairment whenever circumstances indicate their carrying
amount exceeds their fair value and may not be recoverable. As a result of its
continuing operating losses and a decline in its proved reserves at January 1,
1996, from year-earlier pro forma levels, the Company performed an assessment
of the carrying value of Kelley's oil and gas properties indicating an
impairment should be recognized as of year end. Under this analysis, the fair
value for Kelley's proved oil and gas properties was estimated on a depletable
unit basis using escalated pricing and present value discount factors
reflecting risk assessments. The fair value of Kelley's unproved properties
was predicated on current acreage cost estimates. Based on this analysis,
Kelley recognized noncash impairment charges against the carrying values of
its proved and unproved oil and gas properties under FAS 121 aggregating $83.4
million and $66.7 million, respectively, at December 31, 1995.
 
  Contour Transaction. In November 1995, the Company reported that it expected
to be substantially capital constrained by the middle of 1996 due to low
levels of internally generated cash flow and borrowing restrictions. At that
time, the Company implemented an immediate reduction in its drilling
activities and aggressively pursued outside capital in the form of an equity
placement, merger or sale of the Company. Following discussions with potential
acquirors, the Company entered into the Contour Agreements in January 1996,
which provide for a two-stage equity investment of $75 million in the Company
by Contour. Pursuant to the Contour Transaction in February 1996, the Company
appointed John F. Bookout as Chairman, President and Chief Executive Officer
of the Company, and other experienced industry executives to other senior
management positions. See "Company History".
 
  The Contour Transaction enabled the Company's new senior management team to
institute an accelerated developmental drilling program within Kelley's north
Louisiana properties, which has resulted in 35 gross (21.7 net) new wells
being drilled through September 30, 1996. Except for wells still being drilled
at the end of such period, all such wells were completed as producing wells.
The Company expects to initiate drilling on approximately 25 new wells during
the remainder of the year. In addition, the new senior management team has
implemented cost-cutting measures designed to streamline Kelley's operations,
which included a $2.0 million restructuring charge in the first half of 1996
associated primarily with staff reductions and related severance settlements
with certain employees and various reorganization costs. These charges along
with charges incurred in prior periods are included in accounts payable and
accrued expenses on the balance sheet in the amount of $2.2 million, of which
$.5 million is associated with restructuring charges incurred in prior
periods. The Company expects to incur an additional restructuring charge in
the fourth quarter of 1996 associated with staff reductions as a result of
additional consolidation and streamlining of operations. Although these
factors should reduce total overhead costs in 1997, this reduction may not be
fully reflected in the level of reported general and administrative expenses
as a result of a reduction in the level of overhead capitalized and allocated
to exploration expense compared to prior periods.
 
  Hedging Activities. Kelley periodically uses forward sales contracts,
natural gas swap agreements and options to reduce exposure to downward price
fluctuations on its natural gas production. The swap agreements generally
provide for Kelley to receive or make counterparty payments on the
differential between a fixed price and a variable indexed price for natural
gas. Gains and losses realized by Kelley from hedging activities are included
in oil and gas revenues and average sales prices. Kelley's hedging activities
also cover the oil and gas production attributable to the interest in such
production of the public unitholders in Kelley's subsidiary partnerships.
Through a combination of natural gas swap agreements, forward sales contracts
and options, 69.4% of Kelley's natural gas production for the third quarter of
1996 was affected by Kelley's hedging transactions at an average NYMEX quoted
price of $2.17 per MMBTU before transaction and transportation costs on gas
delivered under forward sales contracts. Approximately 57.6% of Kelley's
anticipated natural gas production for the balance of 1996 has been hedged by
natural gas swap agreements, forward sales contracts and options at an average
NYMEX quoted price of $2.25 per MMBTU before transaction and transportation
costs.
 
                                      37
<PAGE>
 
RESULTS OF OPERATIONS
 
  Nine Months Ended September 30, 1995 Compared to Nine Months Ended September
30, 1996. The Company's oil and gas revenues of $40.2 million for the first
nine months of 1996 increased 39.6% compared to $28.8 million on a pro forma
basis in the same period last year primarily as a result of increased gas
prices and production volumes. Production of natural gas during the current
period increased 14.1% to 16.2 million Mcf from 14.2 million Mcf in the first
nine months of 1995, while the average price of natural gas increased 34.3% to
$2.27 per Mcf in the current period from $1.69 per Mcf in the corresponding
period last year. Kelley's production of natural gas peaked in the first
quarter of 1995 and steadily declined in the second and third quarters of 1995
as a result of poor drilling results in south Louisiana. During the fourth
quarter of 1995, the Company's prior management implemented a significant
reduction in drilling activity, which adversely affected production in the
first half of 1996. The Company's current accelerated drilling program is
expected to impact production favorably in the second half of 1996. Production
of crude oil and natural gas liquids during the first nine months of 1996
totaled 181,016 barrels, with an average sales price of $21.29 per barrel
compared to 272,576 barrels at $17.53 per barrel in the first nine months of
1995, representing a volume decrease of 33.6% and a price increase of 21.4% on
a pro forma basis. The decline in oil and condensate volumes reflects the
decline in liquids-rich south Louisiana gas production.
 
  For the first nine months of 1996, revenues from natural gas marketing and
transportation operations, net of associated costs, increased 57.1% to $1.1
million from $.7 million for the same period in 1995.
 
  Production expenses for the first nine months of 1996 decreased 9.5% to $7.6
million from $8.4 million in the same period last year on a pro forma basis,
reflecting lower average costs on production from north Louisiana, which is
increasing in proportion to other higher cost production from south Louisiana.
On a unit basis, production expenses decreased from $.53 per Mcfe in the first
nine months of 1995 to $.44 per Mcfe in the current period.
 
  Exploration costs totaled $4.2 million in the first nine months of 1996 and
$10.9 million on a pro forma basis in the corresponding period of 1995, a
decrease of 61.5%, primarily reflecting a suspension by the new senior
management team of exploratory drilling pending a re-evaluation and
reorientation of Kelley's exploration activities. The decrease in these
expenses also reflects lower geological and geophysical expenses and unproved
leasehold impairment costs.
 
  General and administrative expenses of $7.0 million in the first nine months
of 1996 increased 48.9% compared to $4.7 million on a pro forma basis in the
corresponding period last year. The increase was primarily attributable to
bonuses and interim salaries (aggregating $1.0 million) 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 allocated to exploration expense. The amounts so
capitalized or allocated were $1.4 million and $1.6 million, respectively,
less in 1996 than in the corresponding period of 1995. On a unit basis, these
expenses increased from $.30 per Mcfe in the first nine months of 1995 to $.40
per Mcfe in the current period.
 
  Interest and other debt expenses of $18.4 million in the current period
increased 15.7% from $15.9 million on a pro forma basis in the first nine
months of 1995. The increase in interest expense resulted primarily from
higher interest rates under the 13 1/2% Notes than under the $90.0 million of
bank debt refinanced with proceeds from the offering of the 13 1/2% Notes in
June 1995 and higher average debt levels during the current period. See "--
Liquidity and Capital Resources". Included in its 1996 interest expense of
$14.5 million, the Company recorded noncash charges in the first three
quarters of 1996 of $1.7 million for amortization of debt issuance costs, $.7
million for accretion of note discount, $1.5 million for accretion of debt
valuation discount and $.1 million in imputed interest associated with the
acquisition of oil and gas properties.
 
  Depreciation, depletion and amortization decreased 37.0% from $24.3 million
on a pro forma basis in the first nine months of 1995 to $15.3 million in the
current period, primarily as a result of (i) lower depletion rates
 
                                      38
<PAGE>
 
following impairment charges aggregating $150.1 million recognized in the
fourth quarter of 1995 against the carrying value of Kelley's oil and gas
properties under FAS 121 and (ii) an increase in quantities of proved
developed reserves. On a unit basis, depreciation, depletion and amortization
for oil and gas activities decreased from $1.54 per Mcfe in the first nine
months of 1995 to $.88 per Mcfe in the current period.
 
  In the second quarter of 1996, the Company incurred a $2 million
restructuring charge associated primarily with staff reductions and related
severance settlements with certain employees and various reorganization costs.
 
  Kelley recognized net losses of $12.3 million in the first nine months of
1996 and $33.2 million on a pro forma basis in the same period last year. The
decline in the net losses was primarily attributable to higher oil and gas
prices, increased production and lower depreciation, depletion and
amortization and exploration costs, partially offset by higher interest and
general and administrative expenses.
 
  Year Ended December 31, 1994 Compared to Year Ended December 31, 1995. Pro
forma oil and gas revenues of $38.6 million for 1995 decreased 8.7% compared
to $42.3 million in 1994. Pro forma production of natural gas during 1995
increased 3.8% to 18.8 million Mcf from 18.1 million Mcf in 1994, while the
average price of natural gas decreased 8.0% to $1.72 per Mcf in 1995 from
$1.87 per Mcf in the prior year. Production of crude oil and natural gas
liquids in 1995 totaled 347,697 barrels, with an average sales price of $17.31
per barrel compared to 446,283 barrels at $16.30 per barrel in 1994,
representing a volume decline of 22.1% and a price increase of 6.2% on a pro
forma basis. The decline in oil and gas condensate volumes reflects the
decline in liquids rich south Louisiana gas production.
 
  The decrease in pro forma oil and gas revenues for 1995 was primarily
attributable to production declines in the third and fourth quarters,
including the loss of production from the divestiture of nonstrategic
properties at the beginning of the third quarter and lower natural gas prices.
The prices received for Kelley's natural gas production reflect the benefits
of hedging arrangements, which added $1.8 million to pro forma oil and gas
revenues in 1995. See "--General--Hedging Activities".
 
  Additionally, Kelley recognized a gain of $.8 million from the sale of
nonstrategic properties in July 1995. These nonstrategic properties were
offered for sale due to their high operating costs and low priority within
Kelley's development strategy. Kelley received net proceeds of $6.8 million
for the properties, which accounted for approximately 4.6% of its pro forma
proved reserves as of January 1, 1995. The sales affected production levels
for the second half of the year. See "--Liquidity and Capital Resources--
Liquidity".
 
  Production expenses for 1995 decreased 6.5% on a pro forma basis to $11.5
million from $12.3 million in 1994, primarily reflecting a shift to north
Louisiana production. For the same reason, on a unit basis, pro forma
production expenses decreased to $.55 per Mcfe in 1995 from $.59 per Mcfe in
the prior year.
 
  Pro forma exploration costs totaled $23.7 million in 1995 and $18.1 million
in 1994, an increase of 30.9%. The increase in these expenses resulted from
higher dry hole and leasehold expiration expenses in south Louisiana.
 
  Pro forma general and administrative expenses of $7.4 million in 1995
decreased 10.8% compared to $8.3 million in 1994, reflecting the benefits of
the restructuring implemented at the end of 1994 plus ongoing cost containment
measures. In addition, the Company incurred one-time expenses associated with
the Consolidation of $.6 million during 1994. On a unit basis, these expenses
decreased from $.40 per Mcfe in 1994 to $.35 per Mcfe in 1995.
 
 
                                      39
<PAGE>
 
  On a pro forma basis, interest and other debt expenses of $22.8 million in
1995 increased 83.9% from $12.4 million in the prior year. The increase in
interest expense resulted partially from higher debt levels and from higher
interest rates associated with the issuance of the Notes in June 1995. In
addition to its interest expense, Kelley recorded noncash charges in 1995 of
$3.8 million for amortization of debt issuance costs, of which $1.7 million
represents prepaid financing costs written off in connection with a related
bank debt refinancing. Kelley also recorded noncash charges in 1995 for
accretion of note discount and accretion of debt valuation discount of $.8
million and $1.9 million, respectively.
 
  Depreciation, depletion and amortization decreased 8.9% on a pro forma basis
from $39.7 million in 1994 to $36.2 million in 1995, generally as a result of
lower net capitalized costs in 1995. On a unit basis, depreciation, depletion
and amortization decreased from $1.91 per Mcfe in 1994 to $1.73 per Mcfe in
1995.
 
  In December 1994, the Company implemented a restructuring including staff
reductions of approximately 25% to streamline management and administrative
functions and reduce general and administrative expenses. An additional
management realignment was implemented in the fourth quarter of 1995.
Nonrecurring charges of $1.1 million and $1.8 million primarily related to
severance costs were taken in the fourth quarters of 1995 and 1994,
respectively.
 
  Kelley recognized pro forma net losses before income taxes of $211.5 million
in 1995 and $48.6 million in the prior year. The increased loss primarily
reflects noncash impairment charges of $150.1 million in 1995 against the
carrying value of proved and unproved oil and gas properties, lower gas prices
and higher interest expense and exploration costs, partially offset by lower
charges for depreciation, depletion and amortization.
 
  Year Ended December 31, 1993 Compared to Year Ended December 31, 1994.
Historical oil and gas revenues of $15.5 million for 1994 decreased 21.3%
compared to $19.7 million in 1993. Production of natural gas during 1994
decreased 8.6% to 6.7 million Mcf from 7.3 million Mcf in 1993, while the
average price of natural gas decreased 14.1% to $1.89 per Mcf in 1994 from
$2.20 per Mcf in the prior year. Production of crude oil and natural gas
liquids in 1994 totaled 171,456 barrels, with an average sales price of $16.31
per barrel, compared to 202,064 barrels at $17.84 per barrel in 1993,
representing volume and price declines of 15.1% and 8.6%, respectively. The
decrease in oil and gas production and revenues during 1994 was due primarily
to the 1993 downturn in drilling performance, production declines in certain
existing wells and reductions in Kelley's interests in wells that were subject
to the roll-up of Kelley Partners 1991 Development Drilling Partnership. The
impact of these factors was partially offset by added production from new
wells primarily in the third and fourth quarters of 1994, when historical gas
equivalent production increased 24.3% and 27.1%, respectively, from levels for
such quarters in the prior period.
 
  Production expenses relating to historical oil and gas operations for 1994
and 1993 were $3.8 million and $4.0 million, respectively, a decrease of 5.0%
on a comparative basis. As a percentage of historical oil and gas revenues,
production expenses increased to 24.3% in 1994 from 20.3% in the prior year,
reflecting the decline in natural gas prices. For the same reason, on a unit
basis, production expenses increased to $.49 per Mcfe in 1994 from $.47 per
Mcfe in the prior year.
 
  Historical exploration costs of $7.4 million were expensed in 1994 compared
to $14.2 million in 1993, a decrease of 47.9%, primarily reflecting the focus
on lower risk prospects during 1994. The decrease in these historical expenses
during 1994 was partially offset by an increase in unproved leasehold
impairment provisions, delay rental costs and geological and geophysical
costs.
 
  Historical general and administrative expenses of $5.2 million in 1994
increased 26.8% compared to $4.1 million in 1993, reflecting additional
overhead expenses borne by Kelley prior to the Consolidation. On a historical
basis, these expenses are net of reimbursed overhead incurred on behalf of
Kelley Partners, Kelley's subsidiary developmental drilling partnerships
("DDPs") and other working interest owners of properties operated by Kelley,
aggregating $12.5 million in both 1994 and 1993.
 
 
                                      40
<PAGE>
 
  Historical interest expense of $3.1 million in 1994 decreased 24.4% from
$4.1 million in 1993, primarily reflecting the repayment of borrowings under
the Company's credit facilities in May 1994 from part of the proceeds of a
public offering of Preferred Stock. In addition, the Company incurred debt
conversion costs of $2.5 million and $1.4 million during 1993 and 1994,
respectively. Interest expense was further reduced upon the issuance of
Preferred Stock during September 1994 in exchange for outstanding convertible
subordinated debentures. The decrease in interest expense from lower direct
debt in 1994 was partially offset by Kelley's proportionate share of Kelley
Partners' increased interest expense.
 
  Depreciation, depletion and amortization increased 8.5% on a historical
basis from $18.9 million in 1993 to $20.5 million in 1994, primarily as a
result of an increase in properties subject to amortization per Mcfe. For the
same reason, on a unit basis, depreciation, depletion and amortization
increased to $2.65 per Mcfe in 1994 from $2.21 per Mcfe in the prior year.
 
  In December 1994, the Company implemented a restructuring including staff
reductions of approximately 25% to streamline management and administrative
functions and reduce general and administrative expenses. Nonrecurring charges
of $1.8 million primarily related to severance costs were taken in the fourth
quarter of 1994.
 
  The Company recognized net losses before income taxes of $25.0 million in
1994 and $25.2 million in 1993. In addition, the Company recognized noncash
charges of $1.4 million plus related expenses for the issuance of preferred
stock in exchange for outstanding debentures in the third quarter of 1994 and
$2.1 million plus related expenses for the issuance of common stock of Kelley
Oil upon conversion of $21.9 million principal amount of debentures at a
temporarily reduced conversion rate in the third quarter of 1993.
 
LIQUIDITY AND CAPITAL RESOURCES
 
  General. Kelley's liquidity is materially affected by cash flows generated
from its oil and gas production and was adversely affected by unsuccessful
drilling results in recent years on higher risk prospects in south Louisiana.
In addition, high interest expense and restrictions under Kelley's debt
instruments after the Consolidation limited Kelley's ability to fund drilling
projects. These restrictions required the Company to suspend preferred stock
dividends and seek a substantial equity infusion in early 1996 to avoid a
financial covenant default under the credit agreement in effect at that time.
This effort resulted in the Contour Transaction, completed in February 1996.
The Contour Transaction allowed the Company to retire its outstanding bank
debt, secure a new banking facility and improve its working capital position.
See "Company History".
 
  Although the Contour Transaction has provided Kelley with the means to
continue its drilling operations with the objective of increasing its cash
flow and reserves, the Company continues to have $168.3 million face amount of
debt outstanding, requiring $19.0 million in annual cash interest payments. On
a pro forma basis after giving effect to the Refinancing as of September 30,
1996, the face amount of the Company's debt outstanding would have been $193.7
million and annual cash interest payments on such debt would have been
approximately $18.5 million. Although dividends are prohibited under the New
Credit Facility and are restricted under the Indenture, the outstanding
preferred stock is cumulative, requires dividends to accumulate at the rate of
$4.6 million annually and carries liquidation preferences over the Common
Stock totaling $47.1 million at September 30, 1996, including such dividend
arrearages. The New Credit Facility permits the Company to make a one-time
$4.6 million payment of such dividend arrearages on or prior to May 1, 1997.
The Indenture also permits the Company to make such payment. The Board of
Directors of the Company, however, has not determined whether to make any
payments for dividend arrearages at this time, and any such payment must not
be prohibited under applicable corporate law.
 
  Liquidity. Net cash provided by operating activities, before working capital
adjustments, during the first nine months of 1996 aggregated $8.1 million. The
Company's cash position was increased during the period by $48.0 million from
the issuance of 48.0 million shares of Common Stock in the Contour
Transaction. These increases were offset by $4.1 million of transaction costs.
Funds used in investing and financing activities were comprised of property
and equipment expenditures of $40.9 million and net principal retirements of
$15.0 million on bank
 
                                      41
<PAGE>
 
borrowings. As a result of these activities, cash and cash equivalents
decreased from $6.4 million at December 31, 1995 to $2.5 million as of
September 30, 1996. As of that date, Kelley had a working capital deficit of
$17.1 million, compared to a working capital deficit of $9.2 million at the
end of 1995.
 
  Net cash used in operating activities, before working capital adjustments,
aggregated $4.6 million during 1995. During the year, the Company's cash
position was increased through proceeds of $16.0 million from the issuance of
4.0 million shares of Common Stock in an institutional private placement, net
proceeds of $95.3 million from the sale of the 13 1/2% Notes, proceeds of
$37.1 million from borrowings under the its credit facilities, net proceeds of
$6.8 million from the sale of nonstrategic properties, cash of $1.6 million
received in the Consolidation and proceeds of $.3 million from the exercise of
employee stock options. Funds used in investing and financing activities were
comprised of property and equipment expenditures of $47.0 million, principal
payments of $100.0 million on long-term borrowings and preferred stock
dividends of $6.6 million. As a result of these activities, cash and cash
equivalents decreased from $9.3 million at December 31, 1994 to $6.4 million
at December 31, 1995. As of that date, Kelley had a working capital deficit of
$9.2 million, as compared to a working capital surplus of $3.8 million at the
end of 1994.
 
  The following table sets forth on an unaudited basis historical and pro
forma cash flow from operating activities before working capital adjustments
and EBITDA.
 
<TABLE>
<CAPTION>
                                                                NINE MONTHS
                                                                   ENDED
                                 YEAR ENDED DECEMBER 31,       SEPTEMBER 30,
                             -------------------------------  -----------------
                              1993    1994    1994    1995      1995     1996
                             ------- ------- ------- -------  --------  -------
                                               PRO     PRO      PRO
                                              FORMA   FORMA    FORMA
                                             ------- -------  --------
                                              (IN THOUSANDS)
<S>                          <C>     <C>     <C>     <C>      <C>       <C>
Net cash provided by (used
 in) operating activities
 before working capital
 adjustments................ $ 8,063 $ 1,857 $ 4,917 $(4,124) $    183  $ 9,149
Net cash used in investing
 activities.................  38,520  42,058  75,960  39,535   (25,035)  40,872
EBITDA(1)...................  13,702   8,513  22,509  21,830    17,479   27,025
</TABLE>
--------
(1) EBITDA is calculated as operating income before interest expense and other
    debt expenses, income taxes, exploration costs, restructuring expense,
    depletion, depreciation, amortization, and impairment of oil and gas
    properties. EBITDA is not a measure of cash flow as determined by GAAP.
    The Company has included information concerning EBITDA because EBITDA is a
    measure used by certain investors in determining a company's historical
    ability to service its indebtedness. EBITDA should not be considered as an
    alternative to, or more meaningful than, net income or cash flow as
    determined in accordance with GAAP as an indicator of Kelley's operating
    performance or liquidity. EBITDA is not necessarily comparable to a
    similarly titled measure of another company. The New Credit Facility
    requires the Company to maintain certain financial ratios related to
    EBITDA, and the Indenture limits the Company's ability to incur certain
    indebtedness, pay dividends and engage in certain other transactions if
    certain financial ratios related to EBITDA are not met. See "Description
    of the New Credit Facility" and "Description of the Exchange Notes--
    Certain Covenants".
 
  New Credit Facility. In February 1996, the Company repaid outstanding bank
borrowings of $30.0 million under its then existing credit facility with
proceeds from the Contour Transaction. See "Company History". In connection
with the Contour Transaction, the Company entered into a credit facility,
which was replaced by the New Credit Facility effective as of December 12,
1996. The borrowers under the New Credit Facility are the Company, Kelley Oil
Corporation ("Kelley Oil") and Kelley Operating Company, Ltd. ("Kelley
Operating"), with Concorde Gas Marketing, Inc. (a subsidiary of the Company)
and the Company's subsidiary partnerships as guarantors.
 
  The New Credit Facility provides for a maximum $125 million revolving credit
loan and matures, with all amounts owed thereunder becoming due and payable,
effective December 12, 2006. Borrowings under the New
 
                                      42
<PAGE>
 
Credit Facility are subject to a borrowing base to be determined semi-annually
by the lenders (based in part on the proved oil and gas reserves and other
assets of Kelley) which may be redetermined more frequently at the election of
the lenders or the borrowers. Initially, the borrowing base is $57.5 million.
To the extent that the borrowing base is less than the aggregate principal
amount of all outstanding loans and letters of credit under the New Credit
Facility, 50% of such deficiency must be cured within 90 days and the balance
must be cured within the next 90 days unless such deficiency is a result of an
asset sale, in which case the deficiency must be cured on the date the
borrowing base is re-determined as a result of such sale. Borrowings under the
New Credit Facility are secured by substantially all of the oil and gas assets
of the Company and its subsidiaries and the proceeds therefrom.
 
  So long as no default or event of default (as defined in the New Credit
Facility) is continuing, borrowings under the New Credit Facility bear
interest, at the option of the Borrowers, at either (i) LIBOR plus 1.0% to
1.5% (depending on the level of utilization of the borrowing base) or (ii) the
higher of (a) the agent's prime rate and (b) the federal funds rate plus 0.5%.
The Borrowers incur a quarterly commitment fee ranging from 0.30% to 0.375%
per annum on the average unused portion of the borrowing base, depending upon
the level of utilization.
 
  The New Credit Facility contains covenants which, among other things, limit
the amount of debt Kelley may incur, limit the placement of liens on Kelley's
assets, limit lease transactions, limit Kelley's ability to enter into certain
hedging transactions, restrict the ability of the Company or any of its
subsidiaries to merge with or into another person and prevent the Company from
prepaying certain Subordinated Indebtedness, including the Notes, unless
certain conditions are met. Further, covenants require that, for specified
periods, the Company maintain specified ratios between EBITDA and Senior
Indebtedness and EBITDA and interest on Indebtedness.
 
  The New Credit Facility also prohibits the payment of dividends, except that
it permits the one-time payment on or prior to May 1, 1997 of $4.6 million on
dividend arrearages on the outstanding preferred stock. The Board of Directors
of the Company, however, has not determined whether to make any payments for
dividend arrearages at this time, and any such payment must not be prohibited
under applicable corporate law.
 
  In addition, a reduction in Bessemer's or its affiliates' ownership of the
Company below 20% of the Company's Common Stock is considered an event of
default under the New Credit Facility.
 
  Contour. Pursuant to the second stage of Contour's equity investment in the
Company, Contour has committed to provide an additional $27.0 million in
equity financing upon satisfaction of certain conditions, including the
absence of any Company debt repurchase or redemption obligations, but in no
event later than January 2000. While exercise of such commitment cannot be
assured prior to January 2000, any proceeds received pursuant to such
commitment will reduce Kelley's dependence on outside financing to support
subsequent drilling and acquisition activities. See "Company History--Contour
Transaction".
 
  Recent Acquisition. On September 30, 1996, Kelley closed the purchase of
interests in certain undeveloped reserves located in the Sibley, Sailes, West
Bryceland and Ada fields effective as of July 1, 1996. The Company believes
that this acquisition has increased Kelley's proved reserves by more than 30
Bcfe. The purchase price for the acquired properties was $10 million, subject
to certain adjustments, which the Company financed through borrowings under
the Company's credit facility. The Company also is responsible for certain
capital expenditures incurred by the seller from March 1, 1996 through July 1,
1996.
 
  Industry Partnership. Pursuant to the terms and conditions of a joint
venture with Williams Production--Gulf Coast Company, a unit of the Williams
Companies ("Williams"), effective December 1, 1996, Williams purchased a 50%
interest in Kelley's 27,000 net acreage position in the Houma Embayment in
Terrebonne Parish, Louisiana for a total purchase price of $20.5 million, a
portion of which is committed under the joint venture to drill up to eight
exploration prospects in such area. Williams also acquired 50% of Kelley's
interest in 23 wells and related facilities in this area. Pursuant to the
joint venture, Kelley and Williams have begun a two-rig exploratory drilling
program by spudding their initial well in the Houma Embayment. The Company
believes
 
                                      43
<PAGE>
 
that the joint venture will accelerate the exploration and evaluation of the
Company's south Louisiana properties, where the Company previously had
suspended drilling operations. See "Business and Properties--Significant
Properties".
 
  Capital Commitments. In February 1994, the 1994 Development Drilling Program
(the "1994 DDP") completed a public offering of 20.9 million units at $3.00
per unit on a preemptive basis to public unitholders in Kelley Partners.
Kelley Oil's subscription commitment to the 1994 DDP, after return of capital,
aggregated $56.0 million or 92.2% of the 1994 DDP's total. As of September 30,
1996, Kelley Oil had contributed $46.0 million to the 1994 DDP, together with
interest at a market rate on the portion of its commitment that remained
outstanding after November 1994. Kelley Oil intends to contribute the unfunded
portion of its commitment, which totaled $10.0 million at September 30, 1996,
together with interest, as funds are needed for completion of the 1994 DDP's
drilling program. Kelley Oil is the primary beneficiary of these commitments
as a result of its 92.2% ownership in the 1994 DDP, while approximately $.8
million can be attributable to the public unitholders' interests in the 1994
DDP.
 
  During 1996, Kelley's capital expenditures continue to be focused on
development drilling in north Louisiana, where Kelley currently expects to
participate in drilling a total of approximately 70 gross wells, subject to
regulatory and third party consents. In addition, Kelley plans to balance its
drilling strategy by pursuing acquisition opportunities to expand its reserve
base and operating areas, while utilizing its joint venture with Williams to
explore and develop its higher potential exploratory prospects in south
Louisiana. Kelley has an active program for ongoing evaluation of
opportunities meeting its acquisition criteria. There can be no assurance that
attractive acquisition candidates will be available to the Company on terms it
deems reasonable or that any completed acquisition will ultimately prove to be
a successful undertaking by the Company.
 
  The Company anticipates that, except for any significant property
acquisitions, business combinations or development required by exploratory
success (and subject to price stability), cash flow from operations, and
borrowings under the New Credit Facility will be adequate to fund Kelley's
debt service obligations, expected capital expenditure requirements and
working capital needs. To fully realize Kelley's objectives for property
development and acquisitions, however, the Company may be required to pursue
additional financing alternatives.
 
  Stock-Based Compensation. In October 1995, the Financial Accounting
Standards Board issued Statement of Financial Accounting Standard No. 123,
Accounting for Stock Based Compensation ("FAS 123"), effective for the Company
on January 1, 1996. FAS 123 permits, but does not require, a fair-value based
method of accounting for employee stock option plans, resulting in
compensation expense being recognized in the results of operations when stock
options are granted. The Company has not elected (and does not expect to
elect) to follow the fair-value based method of accounting for stock option
plans, and therefore, no compensation expense is (or will be) recognized.
However, as required by FAS 123, the Company will provide pro forma disclosure
of net income and earnings per share in the notes to its consolidated
financial statements for future periods as if the fair-value based method of
accounting had been applied.
 
  Inflation and Changing Prices. Oil and natural gas prices, as with most
commodities, are highly volatile, have fluctuated during recent years and
generally have not followed the same pattern as inflation.
 
                                      44
<PAGE>
 
                            BUSINESS AND PROPERTIES
 
THE COMPANY
 
  Kelley is engaged in oil and natural gas exploration, development,
production and acquisition. Kelley's activities are concentrated primarily in
two geographic areas: north Louisiana and south Louisiana. At September 30,
1996, approximately 87% of Kelley's proved reserves are located on 48,620
gross (23,668 net) acres within four fields in Webster and Bienville Parishes
of north Louisiana, where its activities are focused on lower-risk development
drilling. Substantially all of the balance of Kelley's proved reserves are
located in south Louisiana, primarily in Terrebonne Parish. Kelley intends to
continue its primary emphasis on development drilling in its north Louisiana
fields where it believes it has opportunities for production growth. Kelley's
exploration activities will focus on its existing leaseholdings in Terrebonne
Parish, where the Company believes successful wells have the potential for
larger reserves and production as compared to development wells in north
Louisiana. In that regard, Kelley is utilizing advanced geophysical techniques
to re-evaluate and refine interpretations of Kelley's 3-D seismic database and
has entered into a joint venture to explore and develop its south Louisiana
properties, which the Company believes will enable it to better manage the
risks and costs associated with the exploration and development of such
properties.
 
  At January 1, 1996, Kelley had estimated proved reserves of 196.3 Bcf of
natural gas and 1,387 Mbbls of oil, aggregating 204.6 Bcfe, with 96% (by
energy content) of its proved reserves attributable to natural gas. At such
date, the present value of estimated future net revenues attributable to
Kelley's proved reserves (based on a December 1995 monthly weighted average
natural gas price of $2.06 per Mcf and a 1995 year-end crude oil price of
$19.73 per Bbl) was $175.8 million, of which $76.7 million was attributable to
proved developed producing reserves, $33.4 million was attributable to proved
developed non-producing reserves and $65.6 million was attributable to proved
undeveloped reserves. At January 1, 1996, Kelley had leaseholdings comprising
117,528 gross (59,718 net) developed acres and 56,287 gross (47,333 net)
undeveloped acres. In addition, pursuant to an acquisition effective as of
July 1, 1996, Kelley purchased undeveloped reserves located on north Louisiana
properties operated by Kelley, which the Company believes added more than 30
Bcfe to Kelley's proved reserves.
 
  In January 1996, the Company entered into financing and related agreements
(the "Contour Agreements") with Contour Production Company L.L.C. ("Contour"),
the successor to a venture formed in 1993 by Bessemer Holdings L.P.
("Bessemer"), the principal investor, and John F. Bookout to pursue
acquisitions of oil and gas reserves. The Contour Agreements provide for a
two-stage $75.0 million equity investment in the Company by Contour. On
February 15, 1996, the first stage of the equity investment was completed
through Contour's $48 million purchase of newly issued shares of Common Stock
(representing on such date 49.8% of the voting shares of the Company) (the
"Contour Transaction"). The remaining $27.0 million of Contour's equity
commitment will be invested upon satisfaction of certain conditions, but in no
event later than January 2000.
 
  In connection with the first stage of Contour's investment in the Company,
Mr. Bookout, formerly President and Chief Executive Officer of Shell Oil
Company, was appointed Chairman, President and Chief Executive Officer of the
Company, and certain other experienced oil industry executives were appointed
to senior management positions within the Company. The Company's new senior
management team, in an effort to increase production and cash flow, redirected
Kelley's capital resources towards an accelerated drilling program in north
Louisiana, initiating 45 gross (22.7 net) wells during the period beginning on
the date of the Contour Transaction and ending September 30, 1996. During the
same period, management was successful in reducing the cost of drilling in
north Louisiana by implementing competitive bidding procedures for drilling
services and by reducing the time required for drilling wells. All wells
initiated by Kelley during such period were completed as producing wells,
except for wells still being drilled at the end of such period. Kelley's
average daily production from its north Louisiana properties for September
1996, was approximately 59 Mmcfe, compared to an average daily production of
approximately 35 Mmcfe during February 1996. Kelley's total daily production
averaged approximately 77 Mmcfe for September 1996, compared to approximately
58 Mmcfe per day during February 1996, representing an increase of 33%.
 
                                      45
<PAGE>
 
STRATEGY
 
  Kelley's strategy is to increase reserves, production and cash flow in a
cost-efficient manner, primarily through the development and exploration of
Kelley's existing properties and through selective acquisitions of oil and gas
reserves.
 
  Develop Existing Assets. Kelley will focus its efforts primarily on lower-risk
development drilling activities within its existing core properties in the
Vacherie Salt Dome region of north Louisiana, where the Company believes it
has opportunities to profitably increase production and cash flow. Since the
Contour Transaction, the Company's new senior management team has refocused
and accelerated Kelley's north Louisiana drilling program. The Company
presently intends to continue dedicating a significant share of its capital
resources to its north Louisiana fields.
 
  Implement a Disciplined Approach to Exploration. The Company's new senior
management team is implementing a disciplined approach to exploration in south
Louisiana. Utilizing current technology, Kelley continues to re-evaluate and
refine interpretations of its 3-D seismic database, which covers substantially
all of its south Louisiana exploration block, and has entered into a joint
venture that will allow it to share the risks and costs associated with
resuming exploratory drilling operations in the area. In this regard, Kelley,
together with any such partners, will focus its exploration efforts in south
Louisiana in the approximately 30,000 gross (27,000 net) acres it holds in the
Houma Embayment area of Terrebonne Parish. To date, operators in this
historically prolific hydrocarbon-producing region have produced in the
aggregate more than six trillion cubic feet of natural gas equivalent.
 
  Pursue Strategic Acquisitions. Kelley will focus its acquisition strategy
primarily on producing oil and gas properties having additional development
potential in order to augment existing production and expand and diversify its
reserve base. Potential acquisitions will be evaluated based upon a number of
factors, including development potential, profit enhancement opportunity,
geographic concentration, operatorship and various reserve and production
attributes. The Company believes that its new senior management team's
experience in evaluating and acquiring oil and gas reserves, together with the
additional financial flexibility provided by the Refinancing (as defined
herein), should enable Kelley to more effectively execute an acquisition
strategy to grow its existing asset base, enhance stockholder value and
increase cash flow.
 
  Reduce Costs. The Company's new senior management team is committed to
achieving and maintaining an efficient cost structure. The initial steps of
Kelley's cost reduction program include the implementation of new information
and business systems, the outsourcing of selected technical and administrative
functions and the utilization of competitive bidding and improved drilling
techniques in north Louisiana to reduce drilling costs.
 
COMPETITIVE STRENGTHS
 
  The Company believes that the following competitive strengths will aid in
the successful implementation of its strategy.
 
  Geographic and Operating Focus. Substantially all of Kelley's reserves and
activities are concentrated in north and south Louisiana. The Company believes
its geographic focus enhances profit potential by allowing it to manage its
large and growing asset base with a relatively small number of employees.
Moreover, the concentration of properties operated by Kelley, particularly in
the Vacherie Salt Dome area of north Louisiana, enables it to achieve cost and
operational efficiencies and to commence recompletion and new drilling
activities quickly and cost-effectively. Kelley is the operator of properties
accounting for approximately 82% of its current production. As operator,
Kelley possesses the ability to enhance profitability by controlling its
operating and overhead expense structure, managing production performance and
regulating capital expenditure projects. During the first nine months of 1996,
Kelley's production expenses for north Louisiana on a per unit basis were $.24
per Mcfe compared to $.35 per Mcfe during 1995. Although Kelley also has been
successful in reducing aggregate operating costs in south Louisiana,
production expenses on a per unit basis ($.90 per Mcfe during the first nine
months of 1996) have increased due to a decline in production in such area.
 
  Quality Reserves. Kelley's proved reserves as of January 1, 1996, are
relatively long-lived (9.8 reserves to production ratio). Based on past
production profiles, the Company believes that its north Louisiana wells
 
                                      46
<PAGE>
 
ordinarily will produce half of their estimated ultimate reserves in the first
five years of their productive lives (generally in excess of 20 years) and
will produce at lower but more constant rates for the remainder of such lives.
From January 1, 1994 through December 31, 1995, Kelley participated in 47
gross (18.8 net) wells (70% of which were drilled by Kelley), all of which
have been completed as producing wells, at an average development cost of $.60
per Mcfe with gross average reserves per well of 4.1 Bcfe. These completed
wells tested at daily rates of up to 16,600 Mcfe and had an average initial
daily production rate of 5,200 Mcfe. During the period beginning with the
Contour Transaction and ending September 30, 1996, Kelley drilled 45 gross
(22.7 net) wells in north Louisiana, which were developed at a lower average
cost per Mcfe than those drilled in 1994 and 1995. The Company believes the
high initial production rates, relatively short pay-back periods and long
lives of its north Louisiana wells provide a solid base from which to pursue
its exploration strategy in south Louisiana as well as its reserve acquisition
strategy.
 
  Favorable Price and Cost Structure. Kelley's oil and gas reserves are located
in close proximity to pipeline transportation and key market locations, and,
therefore, generally command favorable prices. In north Louisiana, Kelley is
able to achieve favorable operating margins because lease operating expenses
are generally low as a result of relatively low formation pressures and
minimal liquid hydrocarbon and salt water production. Kelley's south Louisiana
properties are generally closer to transportation and market locations, and
production from these reserves generally receives higher prices because of its
rich condensate content. These higher prices partially offset the relatively
higher operating costs associated with higher formation pressures, inland
water locations and salt water disposal in south Louisiana.
 
  Effective Use of Technology. Kelley applies advanced technology to lower the
risks and costs of exploration and development. The Company, together with its
partner, is re-evaluating and refining Kelley's 3-D seismic database, which
covers 125 square miles, including virtually all of its south Louisiana
exploration prospects. This analysis will increase the possibility of success
and allow for better well placement. Moreover, Kelley invests in computer-
aided exploration and development hardware and software and has the background
and operating experience to engage highly competent and experienced technical
consultants, as needed.
 
  Experienced and Proven Management Team. The four members of the Company's new
senior management team have an average of approximately 30 years of experience
in the oil and gas industry and Kelley's operating managers possess
significant experience in its operating areas. In addition, the new senior
management team has been supported in its undertaking by the substantial
equity investment arising from the Contour Transaction. Through various
performance incentive programs, the Company believes that management, employee
and investor interests are strongly aligned.
 
DESCRIPTION OF PROPERTIES
 
  Kelley's properties are located principally in Louisiana. As of January 1,
1996, Kelley owned interests in a total of 371 gross (156.8 net) producing
wells, of which 198 wells were operated by Kelley, accounting for 82% of
Kelley's current production. As of that date, Kelley had leaseholdings
covering 117,528 gross (59,718 net) developed acres and 56,287 gross (47,333
net) undeveloped acres. Approximately 96% of Kelley's proved oil and gas
reserves (by energy content) as of January 1, 1996, was natural gas. The
reserves to production ratio for these properties (based on 1995 production
rates) was estimated to be 9.8 as of January 1, 1996.
 
SIGNIFICANT PROPERTIES
 
  Kelley's core natural gas properties in north Louisiana are located in the
Sailes, Sibley, West Bryceland and Ada fields of Webster and Bienville
Parishes, while its core properties in south Louisiana are concentrated in
Terrebonne Parish. Production is primarily from the Hosston (north Louisiana)
and Miocene (south Louisiana) formations. Substantially all of Kelley's oil
and gas properties are pledged to secure borrowings under the New Credit
Facility. The following table sets forth certain information about Kelley's
interests in its most significant fields, together with information for all
other fields combined. Pro forma production data gives effect to the
Consolidation as of January 1, 1995.
 
 
                                      47
<PAGE>
 
                         SIGNIFICANT PROVED PROPERTIES
 
<TABLE>
<CAPTION>
                                   PROVED RESERVES AS OF
                                      JANUARY 1, 1996                           PRODUCTION
                         ----------------------------------------- -----------------------------------------
                                                                     TWELVE MONTHS
                                                                         ENDED          NINE MONTHS ENDED
                                                    PRESENT VALUE  DECEMBER 31, 1995    SEPTEMBER 30, 1996
                                            GAS      OF ESTIMATED  -------------------- --------------------
                           OIL     GAS   EQUIVALENT   FUTURE NET      OIL      GAS         OIL      GAS
PROPERTY                 (MBBLS) (MMCF)   (MMCFE)      REVENUES     (MBBLS)   (MMCF)     (MBBLS)   (MMCF)
--------                 ------- ------- ---------- --------------  -------  ----------  -------   ------
                                                                       PRO FORMA
                                                                   --------------------
                                                    (IN THOUSANDS)
<S>                      <C>     <C>     <C>        <C>            <C>       <C>        <C>       <C>
NORTH LOUISIANA:
  Sibley Field..........    128   60,840   61,608      $ 53,112            4      2,347         7      3,977
  Sailes Field..........    131   52,844   53,630        44,033           24      5,821        27      4,826
  West Bryceland Field..     82   43,744   44,236        28,776            4      1,462         6      2,170
  Ada Field.............     22   13,398   13,530        11,885            1        425         2        919
SOUTH LOUISIANA(1):
  Orange Grove/
   Humphreys Field......    172    8,266    9,298        11,979           69      3,136        32      1,399
  Ouiski Bayou Field....    202    2,690    3,902         4,902           46      1,116        19        524
  Fire Island Field.....     36    1,602    1,818         3,374           25      1,060        12        614
OTHER:
  As a group............    614   12,889   16,573        17,700          175      3,461        76      1,792
                          -----  -------  -------      --------      ------- ----------   ------- ----------
      Total.............  1,387  196,273  204,595      $175,761          348     18,828       181     16,221
                          =====  =======  =======      ========      ======= ==========   ======= ==========
</TABLE>
--------
(1) Effective December 1, 1996, Kelley entered into a joint venture whereby it
    sold in the Houma Embayment, including in the Orange Grove/Humphreys and
    Ouiski Bayou fields, 50% of its net acreage position as well as 50% of its
    interest in 23 wells and related facilities in such area. See
    "Management's Discussion and Analysis of Financial Condition and Results
    of Operations--Liquidity and Capital Resources".
 
  Additional information regarding these fields is set forth below. Well and
reserve information is provided as of January 1, 1996.
 
  NORTH LOUISIANA
 
  Kelley's operations in this region are focused primarily on four contiguous
fields in the Vacherie Salt Dome area. Production is primarily from the
Hosston Sandstone interval with an average thickness of 3,000 feet. Wells are
typically drilled to a maximum depth of approximately 10,500 feet. Operations
in this region do not typically experience high formation pressures or
significant associated liquid production or salt water disposal. Recently,
increases in recoveries from north Louisiana wells have been achieved from
revised interpretations of geological fault systems, revised fracture
stimulation techniques and regulatory changes that allowed the commingling of
production from multiple zones. Based on past production profiles, the Company
believes that its north Louisiana wells will ordinarily produce half of their
estimated ultimate reserves in the first five years of their productive lives
(generally in excess of 20 years) and will produce at lower but more constant
rates for the remainder of such lives. At September 30, 1996, Kelley operated
an aggregate of 153 gross (84.2 net) wells in this region.
 
  Sibley Field. The Sibley Field is located in Webster Parish, Louisiana. The
Sibley Field proved reserves were 58% developed and 28.9% producing as of
December 31, 1995. As of September 30, 1996, Kelley had interests in 57 gross
(15.9 net) wells producing primarily from the Hosston formation at depths
ranging from 4,500 to 9,000 feet. Kelley operates 28 of the wells. Kelley
completed as producers 11 gross (3.2 net) wells in the Sibley Field from
January 1, 1996, through September 30, 1996, and was in the process of
drilling 1 gross (.4 net) well in this field on September 30, 1996.
 
                                      48
<PAGE>
 
  Sailes Field. The Sailes Field is located in Bienville Parish, Louisiana. The
Sailes Field proved reserves were 57% developed and 39.1% producing as of
December 31, 1995. As of September 30, 1996, Kelley had interests in 78 gross
(41.3 net) wells producing from the Hosston formation at depths ranging from
7,000 to 10,500 feet. Kelley operates 69 of the wells. Kelley completed as
producers 12 gross (7.5 net) wells in the Sailes Field from January 1, 1996,
through September 30, 1996.
 
  West Bryceland Field. The West Bryceland Field is located in Bienville
Parish, Louisiana. The West Bryceland Field proved reserves were 43% developed
and 14.8% producing as of December 31, 1995. As of September 30, 1996, Kelley
had interests in 69 gross (24.8 net) wells producing from the Hosston formation
at depths ranging from 6,500 to 10,500 feet. Kelley operates 39 of the wells.
Kelley completed as producers 10 gross (4.6 net) wells in the West Bryceland
Field from January 1, 1996, through September 30, 1996, and was in the process
of drilling 5 gross (3.3 net) wells in this field on September 30, 1996.
 
  Ada Field. The Ada Field is located in Bienville and Webster Parishes,
Louisiana. The Ada Field proved reserves were 45% developed and 11.5% producing
as of December 31, 1995. As of September 30, 1996, Kelley had interests in 17
gross (7.7 net) wells producing primarily from the Hosston formation at depths
ranging from 6,000 to 10,000 feet. Kelley operates 10 of the wells. Kelley
completed as producers 2 gross (.9 net) wells in the Ada Field from January 1,
1996, through September 30, 1996.
 
  Recent Acquisition. On September 30, 1996, Kelley closed the purchase of
interests in certain undeveloped reserves located in the Sibley, Sailes, West
Bryceland and Ada fields effective as of July 1, 1996. The Company believes
that this acquisition has increased Kelley's proved reserves by more than 30
Bcfe. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations--Liquidity and Capital Resources".
 
  SOUTH LOUISIANA
 
  Kelley's operations in this region primarily are focused on four fields in
the Houma Embayment area and one field in nearby Vermilion Parish. The Houma
Embayment is composed of high-quality reservoir rock, contributing to high
production rates. Wells are typically drilled to a depth of approximately
11,000 to 17,000 feet. Kelley's south Louisiana properties generally are
located in close proximity to transportation and market locations, and
production therefrom generally receives higher prices because of its rich
condensate content. The Company believes these factors partially offset the
higher operating costs associated with higher formation pressures, salt water
disposal and liquid hydrocarbon handling associated with the region. Kelley
operates an aggregate of 54 gross (49.0 net) wells in this region and currently
is not drilling any wells in the region. Kelley's average working interest in
these properties is approximately 90%. The three most significant fields are
described below.
 
  Orange Grove/Humphreys Field. The Orange Grove/Humphreys Field is located in
Terrebonne Parish, Louisiana. All Orange Grove/Humphreys Field proved reserves
were developed and 75.7% were producing as of December 31, 1995. As of
September 30, 1996, Kelley had interests in 15 gross (12.8 net) wells producing
primarily from the Miocene 1st Hollywood and Bourg formations at depths ranging
from 2,500 to 13,900 feet. Kelley operates 13 of the wells.
 
  Ouiski Bayou Field. The Ouiski Bayou Field is located in Terrebonne Parish,
Louisiana. All Ouiski Bayou Field proved reserves were developed and producing
as of December 31, 1995. As of September 30, 1996, Kelley had interests in 2
gross (1.7 net) wells producing from the Cib op and KK formations at depths
ranging from 14,880 to 18,000 feet. Kelley operates all of the wells.
 
  Fire Island Field. The Fire Island Field is located in Vermilion Parish,
Louisiana. All Fire Island proved reserves were developed and producing as of
December 31, 1995. As of September 30, 1996, Kelley had an interest in 1 gross
(.95 net) well, which is operated by Kelley producing from the MA-36 formation
at a depth of 14,400 feet.
 
  Industry Partnership. Pursuant to the terms and conditions of a joint venture
with Williams, effective December 1, 1996, Williams purchased a 50% interest in
Kelley's 27,000 net acreage position in the Houma Embayment, including in the
Orange Grove/Humphreys and Ouiski Bayou fields, for a total purchase price of
$20.5
 
                                       49
<PAGE>
 
million, a portion of which is committed under the joint venture to drill up
to eight exploration prospects in such area. Williams also acquired 50% of
Kelley's interest in 23 wells and related facilities in this area. Pursuant to
the joint venture, Kelley and Williams have begun a two-rig exploratory
drilling program by spudding their initial well in the Houma Embayment. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources".
 
PROVED RESERVES
 
  General. Reserve estimates contained herein were prepared by H. J. Gruy &
Associates, Inc. ("Gruy") independent petroleum engineers, as of January 1,
1996, and were prepared by Kelley and reviewed by Gruy at January 1, 1994 and
1995. 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 not escalated but are held constant over
the estimated life of the reserves. See "Risk Factors--Uncertainties in
Estimating Reserves and Future Net Revenues".
 
  Quantities. The following table sets forth the estimated quantities of
proved and proved developed reserves of crude oil (including condensate and
natural gas liquids) and natural gas owned by Kelley for the years ended
December 31, 1993, 1994 and 1995 and principal components of the changes in
the quantities of reserves for each of the periods then ended. See "Risk
Factors--Uncertainties in Estimating Reserves and Future Net Revenues".
 
                                PROVED RESERVES
 
<TABLE>
<CAPTION>
                                     FOR THE YEAR ENDED DECEMBER 31,
                              ------------------------------------------------
                                   1993             1994            1995
                              ---------------  --------------  ---------------
                                OIL     GAS      OIL    GAS      OIL     GAS
                              (MBBLS) (MMCF)   (MBBLS) (MMCF)  (MBBLS) (MMCF)
                              ------- -------  ------- ------  ------- -------
<S>                           <C>     <C>      <C>     <C>     <C>     <C>
PROVED RESERVES:
  Beginning balance..........  1,837   69,804   1,114  64,875   1,236   93,612
  Revisions of previous
   estimates.................   (913) (23,177)     75  16,055    (558) (27,006)
  Dilutive effect of
   offerings.................   (210)  (5,030)     --      --      --       --
  Purchases of oil and gas
   properties................     --       --      --      --   1,756  127,962
  Revisions of purchased oil
   and gas properties........     --       --      --      --    (766) (37,021)
  Extensions, discoveries,
   improved recovery and
   other additions...........    602   30,605     218  19,379     156   66,864
  Sale of reserves...........     --       --      --      --    (118) (10,388)
  Production.................   (202)  (7,327)   (171) (6,697)   (319) (17,750)
                               -----  -------   -----  ------   -----  -------
  Ending balance.............  1,114   64,875   1,236  93,612   1,387  196,273
                               =====  =======   =====  ======   =====  =======
PROVED DEVELOPED RESERVES:
  Producing..................    365   17,434     414  28,806     669   63,488
  Non-producing..............    237   12,658     260  19,665     528   47,799
                               -----  -------   -----  ------   -----  -------
    Total proved developed...    602   30,092     674  48,471   1,197  111,287
                               =====  =======   =====  ======   =====  =======
</TABLE>
 
  Reserves as of January 1, 1996, declined 14.9% to 204.6 Bcfe when compared
to pro forma reserves of 240.5 Bcfe reported as of January 1, 1995 (after
giving effect to the Consolidation). In 1995, Kelley added 13.6 Bcfe of
reserves through successful drilling in north Louisiana and added 53.2 Bcfe
from 36 gross (12.5 net) proved undeveloped reserve locations in core north
Louisiana fields. These additions were offset by downward revisions resulting
from the reassessment of certain developed and undeveloped south Louisiana
properties aggregating 11.6 Bcfe and 39.6 Bcfe, respectively, and the
divestiture of certain nonstrategic properties, which accounted for
approximately 11.1 Bcfe. Upward revisions to reserve estimates during 1994
were related to successful developmental drilling, which allowed additional
reserves to be categorized as proved. Downward revisions to reserve estimates
in 1993 reflected unsuccessful drilling activities in south Louisiana. The
dilutive effect of offerings in 1993 relates to the sale of units by Kelley
Partners, which reduced Kelley Oil's proportional interest in Kelley Partners'
reserves.
 
                                      50
<PAGE>
 
  The addition of reserves in 1995 attributable to "Purchases" is attributable
to the Consolidation. At the end of 1995, further evaluation led to revisions
of the quantities of reserves acquired in the Consolidation.
 
  Values. The following table sets forth estimated future net revenues from
the production and sale of Kelley's estimated proved reserves and the present
value of estimated future net revenues on a historical basis as of January 1,
1994, on a pro forma basis as of January 1, 1995, and on a historical basis as
of January 1, 1996. Pro forma information gives effect to the Consolidation as
of January 1, 1995.
 
  The prices used in the information presented below were based on oil and
natural gas prices received at the end of each reported period without
escalation. Gas prices as of any month end, as customary, are based upon the
weighted average price of gas for such month. The prices as of December 31,
1995 were $2.06 per Mcf of natural gas and $19.73 per barrel of crude oil,
compared to prices as of December 31, 1993 and 1994 of $2.49 and $1.66,
respectively, per Mcf of natural gas and $13.80 and $15.65, respectively, per
barrel of crude oil.
 
  Estimated future net revenues are computed after giving effect to estimated
future development and production costs, based on year-end costs and assuming
the continuation of existing economic conditions. The calculation does not
take into account the effect of various cash outlays, including general and
administrative costs and interest expense, and does not give effect to
estimated future income taxes. In computing the present value of the estimated
future net revenues, a discount factor of 10% was used to adjust for the
present value of estimated future net revenues. Present value, regardless of
the discount rate used, is materially affected by assumptions about the timing
of future production, which may prove to have been inaccurate. The following
reserve value data represents estimates only, which are subject to
considerable uncertainty. See "Risk Factors--Uncertainties in Estimating
Reserves and Future Net Revenues". Additional reserve information is included
in Note 15 ("Supplementary Information") of the Consolidated Financial
Statements included elsewhere in this Prospectus.
 
              ESTIMATED FUTURE NET REVENUES FROM PROVED RESERVES
 
<TABLE>
<CAPTION>
                                                        AS OF JANUARY 1,
                                                 --------------------------
                                                   1994     1995     1996
                                                 -------- -------- --------
                                                         PRO FORMA
                                                         ---------
                                                       (IN THOUSANDS)
<S>                                              <C>      <C>      <C>     
Estimated future net revenues from production
 of proved reserves:
  Proved developed.............................  $ 65,644 $169,444 $195,376
  Proved undeveloped...........................    67,234  102,983  123,430
                                                 -------- -------- --------
    Total proved...............................  $132,878 $272,427 $318,806
                                                 ======== ======== ========
Present value of estimated future net revenues:
  Proved developed.............................  $ 43,207 $107,025 $110,114
  Proved undeveloped...........................    32,059   56,590   65,647
                                                 -------- -------- --------
    Total proved...............................  $ 75,266 $163,615 $175,761
                                                 ======== ======== ========
</TABLE>
 
  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.
 
  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 Prospectus are only
estimates. Reserve estimates are inherently imprecise and may be expected to
change as additional information becomes available. Furthermore, estimates of
oil and gas reserves, of necessity, are projections based on engineering data,
and there are uncertainties inherent in the interpretation of such data as
well as the projection of future rates of production and the timing of
development expenditures. Reservoir engineering is a subjective process of
 
                                      51
<PAGE>
 
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 revenues 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 likely that
variances from the estimates will be material. In addition, the estimates of
future net revenues from proved reserves of Kelley and the present value
thereof are based upon certain assumptions about future production levels,
prices and costs that may not be correct when judged against actual subsequent
experience. The Company emphasizes with respect to the estimates prepared by
independent petroleum engineers that the discounted future net revenues should
not be construed as representative of the fair market value of the proved
reserves owned by Kelley since discounted future net revenues 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. Actual results will differ, and are likely to differ
materially, from the results estimated. Accordingly, investors in Exchange
Notes are cautioned not to place undue reliance on the reserve data included
in this Prospectus. See "Risk Factors--Uncertainties in Estimating Reserves
and Future Net Revenues".
 
PRODUCTION, PRICE AND COST HISTORY
 
  The following table sets forth certain production data, the average sales
prices and average production expenses attributable to Kelley's properties on
a historical basis for 1993, 1994 and 1995 and for the nine months ended
September 30, 1996, and on a pro forma basis for 1994 and 1995 after giving
effect to the Consolidation as of January 1, 1994. Detailed additional
information concerning Kelley's oil and gas production activities is contained
in the Supplementary Information in Note 15 to the Consolidated Financial
Statements included elsewhere in this Prospectus.
 
<TABLE>
<CAPTION>
                                                                    NINE MONTHS
                                  YEAR ENDED DECEMBER 31,              ENDED
                          ---------------------------------------- SEPTEMBER 30,
                           1993   1994   1995    1994      1995        1996
                          ------ ------ ------ --------- --------- -------------
                                               PRO FORMA PRO FORMA
                                               --------- ---------
<S>                       <C>    <C>    <C>    <C>       <C>       <C>
PRODUCTION DATA:
 Oil and other liquid
  hydrocarbons (Mbbls)..     202    171    319     446       348         181
 Natural gas (Mmcf).....   7,327  6,697 17,750  18,141    18,828      16,221
 Natural gas equivalent
  (Mmcfe)...............   8,539  7,723 19,664  20,817    20,916      17,307
AVERAGE SALES PRICE PER
 UNIT:
 Oil and other liquid
  hyrocarbons (per
  Bbl)..................  $17.84 $16.31 $17.37  $16.30    $17.31      $21.29
 Natural gas (per Mcf)..    2.20   1.89   1.71    1.87      1.72        2.27
 Natural gas equivalent
  (per Mcfe)............    2.31   2.01   1.83    2.03      1.84        2.35
AVERAGE PRODUCTION
EXPENSES (PER MCFE).....     .47    .49    .55     .59       .55         .44
</TABLE>
 
PRODUCTION PERFORMANCE
 
  Kelley's equivalent gas production for the nine months ended September 30,
1996, represents on a pro forma basis a 9.4% increase when compared to the
same period last year. On a pro forma basis, equivalent gas production in 1995
was essentially unchanged from 1994. Within its core properties in north
Louisiana, Kelley participated in the completion as producing wells 21 gross
(8.7 net), 26 gross (10.1 net) and 48 gross (24.1 net) wells as to which
drilling was initiated in 1994, 1995 and the first nine months of 1996,
respectively. However,
 
                                      52
<PAGE>
 
Kelley's production during these periods was adversely affected by several
factors, including production declines in its south Louisiana properties where
certain major wells performed below expectations, disappointing drilling
results in south Louisiana and the sale of nonstrategic properties in July
1995.
 
  In 1995, revised completion techniques contributed to higher initial flow
rates in many of Kelley's new north Louisiana wells, some of which were not
completed and brought on production until late in 1995 and thus did not
contribute significantly to production until 1996. After declining to a total
of approximately 4.4 Bcfe in the third quarter of 1995, equivalent gas
production has increased 22.7% to 5.4 Bcfe during the second quarter of 1996.
In the second quarter of 1996, Kelley further increased its focus on north
Louisiana operations with the initiation of a six-rig drilling program. As a
result of recent well completions in north Louisiana and the accelerated
drilling program, Kelley anticipates further improvement in production levels
in that area.
 
PRODUCTIVE WELLS AND ACREAGE
 
  As of December 31, 1995, Kelley had leaseholdings comprising 117,528 gross
(59,718 net) developed acres and 56,287 gross (47,333 net) undeveloped acres,
all located within the continental United States. The oil and gas leases in
which Kelley has an interest are for varying primary terms and many,
particularly in south Louisiana, require the payment of delay rentals in lieu
of drilling operations. In north Louisiana most of Kelley's leasehold
interests are held by production, that is, so long as natural gas and oil are
produced from the properties covered thereby, the leases continue
indefinitely. The leases may be surrendered at any time by notice to the
lessors, by the cessation of production or by failure to make timely payment
of delay rentals.
 
  As of December 31, 1995, Kelley had working interests in 344 gross (145.4
net) productive gas wells and 27 gross (11.4 net) productive oil wells
(including producing wells and wells capable of production). The following
table sets forth Kelley's ownership interests in its leaseholds as of December
31, 1995.
 
<TABLE>
<CAPTION>
                                         DEVELOPED(1)         UNDEVELOPED(2)
                                     --------------------- ---------------------
                                     GROSS ACRES NET ACRES GROSS ACRES NET ACRES
                                     ----------- --------- ----------- ---------
   <S>                               <C>         <C>       <C>         <C>
   Louisiana........................   106,649    58,508     56,287     47,333
   Texas............................     8,747     1,083         --         --
   Other states.....................     2,132       127         --         --
                                       -------    ------     ------     ------
     Total..........................   117,528    59,718     56,287     47,333
                                       =======    ======     ======     ======
</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.
 
                                      53
<PAGE>
 
DEVELOPMENT AND EXPLORATION
 
  The following table sets forth the number of gross and net productive and
dry development wells and exploratory wells drilled by Kelley in north
Louisiana and in south Louisiana and elsewhere during the periods indicated,
together with pro forma information giving effect to the Consolidation as of
January 1, 1994.
 
<TABLE>
<CAPTION>
                                         YEAR ENDED DECEMBER 31,
                         -------------------------------------------------------  NINE MONTHS ENDED
                             1993          1994          1994          1995      SEPTEMBER 30, 1996
                         ------------- ------------- ------------- ------------- -------------------
                         GROSS   NET   GROSS   NET   GROSS   NET   GROSS   NET     GROSS      NET
                         ------ ------ ------ ------ ------ ------ ------ ------ -------------------
                                                       PRO FORMA     PRO FORMA
                                                     ------------- -------------
<S>                      <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>       <C>
NORTH LOUISIANA:
 Exploratory wells:
   Oil..................     --     --     --     --     --     --     --     --        --        --
   Natural gas..........     --     --     --     --     --     --     --     --        --        --
   Dry..................      1    .61     --     --     --     --     --     --        --        --
                         ------ ------ ------ ------ ------ ------ ------ ------ --------- ---------
     Total..............      1    .61     --     --     --     --     --     --        --        --
                         ====== ====== ====== ====== ====== ====== ====== ====== ========= =========
 Development wells:
   Oil..................     --     --     --     --     --     --      1    .05         1       .04
   Natural gas..........      6   1.10     22   5.92     22   8.53     22   9.26        43     21.40
   Dry..................      2    .22     --     --     --     --     --     --        --        --
                         ------ ------ ------ ------ ------ ------ ------ ------ --------- ---------
     Total..............      8   1.32     22   5.92     22   8.53     23   9.31        44     21.44
                         ====== ====== ====== ====== ====== ====== ====== ====== ========= =========
 Total north Louisiana:
   Producing............      6   1.10     22   5.92     22   8.53     23   9.31        44     21.44
   Dry..................      3    .83     --     --     --     --     --     --        --        --
                         ------ ------ ------ ------ ------ ------ ------ ------ --------- ---------
     Total..............      9   1.93     22   5.92     22   8.53     23   9.31        44     21.44
                         ====== ====== ====== ====== ====== ====== ====== ====== ========= =========
SOUTH LOUISIANA AND
 OTHER:
 Exploratory wells:
   Oil..................     --     --     --     --     --     --     --     --        --        --
   Natural gas..........      3   1.30      3   1.48      3   2.09     --     --        --        --
   Dry..................      4   1.75      3   1.98      3   2.78      1    .95        --        --
                         ------ ------ ------ ------ ------ ------ ------ ------ --------- ---------
     Total..............      7   3.05      6   3.46      6   4.87      1    .95        --        --
                         ====== ====== ====== ====== ====== ====== ====== ====== ========= =========
 Development wells:
   Oil..................     --     --     --     --     --     --     --     --        --        --
   Natural gas..........      9   3.88      6   3.25      6   4.57      4   3.78        --        --
   Dry..................     --     --      1    .63      1    .89      1    .95        --        --
                         ------ ------ ------ ------ ------ ------ ------ ------ --------- ---------
     Total..............      9   3.88      7   3.88      7   5.46      5   4.73        --        --
                         ====== ====== ====== ====== ====== ====== ====== ====== ========= =========
 Total south Louisiana
  and other:
   Producing............     12   5.18      9   4.73      9   6.66      4   3.78        --        --
   Dry..................      4   1.75      4   2.61      4   3.67      2   1.90        --        --
                         ------ ------ ------ ------ ------ ------ ------ ------ --------- ---------
     Total..............     16   6.93     13   7.34     13  10.33      6   5.68        --        --
                         ====== ====== ====== ====== ====== ====== ====== ====== ========= =========
</TABLE>
 
  On September 30, 1996, Kelley had 8 gross (3.91 net) development wells in
progress, all in north Louisiana.
 
MARKETING
 
  Kelley does not refine or process any of the oil and natural gas it
produces. Kelley's natural gas production is sold to various purchasers
typically in the areas where the natural gas is produced. Kelley currently is
able to sell, under contract or in the spot market, all of its natural gas at
current market prices. Substantially all of Kelley's natural gas is sold under
short-term contracts or contracts providing for periodic adjustments or in the
spot market; therefore, its revenue streams are sensitive to changes in
current market prices. Kelley's sales of crude oil, condensate and natural gas
liquids generally are made at posted field prices, which are not subject to
regulation.
 
 
                                      54
<PAGE>
 
  In addition to marketing Kelley's natural gas production, a subsidiary of
the Company provides gas transportation arrangements, supervises gas gathering
operations and performs revenue receipt and disbursement services as well as
regulatory filing, recordkeeping, inspection, testing and monitoring
functions. Another subsidiary of the Company coordinates the connection of
newly drilled wells to various pipeline systems, does gas market surveys and
oversees gas balancing with its various gas gatherers and transporters. During
1994, Kelley received from certain of its members and from unrelated customers
either fees or a marketing differential at the rate of $.05 per MMBTU of gas
sold and delivered under these arrangements. For 1995 and the first nine
months of 1996, the marketing fee was modified to 2% of the resale price for
marketed natural gas. The Company believes that similar arrangements are
customary among natural gas producers and their marketing affiliates. See
"Selected Consolidated Financial Data" and the Consolidated Financial
Statements included elsewhere in this Prospectus for information as to the
Company's net gas marketing revenues, which include such marketing fees
received by such subsidiary.
 
  Kelley believes that its activities are not currently constrained by a lack
of adequate transportation systems or system capacity and does not foresee any
material disruption in available transportation for its production. However,
there can be no assurance that Kelley will not encounter any such constraints
in the future. In such event, Kelley would be forced to seek alternate sources
of transportation and may face increased costs.
 
HEDGING
 
  The prices received for Kelley's natural gas production are subject to
market fluctuations. From time to time, Kelley has used forward sales
contracts, natural gas swap agreements and options to minimize the exposure of
Kelley's natural gas production to downward price fluctuations. Kelley's
hedging activities also cover the natural gas production attributable to the
interest in such production of the public unitholders in Kelley's subsidiary
partnerships. Through a combination of swap agreements and forward sales
contracts, 13.9 million MMBTUs of Kelley's natural gas production for 1995
were affected by hedging transactions at an average NYMEX quoted price of
$1.78 per MMBTU before transaction costs and transportation costs on gas
delivered under forward sales contracts. For the first nine months of 1996,
through a combination of natural gas swap agreements and forward sales
contracts, approximately 69.4% of Kelley's anticipated natural gas production
was affected by hedging transactions at an average NYMEX quoted price of $2.17
per MMBTU before transaction and transportation costs on gas delivered under
forward sales contracts. Approximately 57.6% of Kelley's anticipated natural
gas production for the balance of 1996 had been hedged through swap agreements
or forward sales contracts at an average NYMEX quoted price of $2.25 per MMBTU
before transaction and transportation costs on gas delivered under forward
sales contracts. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations--General".
 
COMPETITION
 
  Kelley operates in a highly-competitive environment with respect to
acquiring reserves, marketing oil and natural gas and securing trained
personnel. Many of Kelley's larger competitors possess and employ financial
and personnel resources substantially greater than those available to Kelley.
Such companies may be able to pay more for productive oil and natural gas
properties and to define, evaluate, bid for and purchase a greater number of
properties than Kelley's financial or personnel resources permit. Kelley's
ability to acquire additional reserves in the future will be dependent upon
its ability to evaluate and select suitable properties and to consummate
transactions in a highly-competitive environment. In addition, there is
substantial competition for capital available for investment in the oil and
natural gas industry. There can be no assurance that Kelley will be able to
 
                                      55
<PAGE>
 
compete successfully in the future in acquiring reserves, developing reserves,
marketing hydrocarbons, attracting and retaining quality personnel, and
raising additional capital.
 
REGULATION
 
  Kelley's operations are subject to extensive and continually changing
regulation, as legislation affecting the oil and natural gas industry is under
constant review for amendment and expansion. Many departments and agencies,
both federal and state, are authorized by statute to issue and have issued
rules and regulations binding on the oil and natural gas industry and its
individual participants. The failure to comply with such rules and regulations
can result in substantial penalties. The regulatory burden on the oil and
natural gas industry increases Kelley's cost of doing business and,
consequently, affects its profitability. However, Kelley does not believe that
it is affected in a significantly different manner by these regulations than
are its competitors in the oil and natural gas industry. Because of the
numerous and complex federal and state statutes and regulations that may
affect Kelley, directly or indirectly, the following discussion of certain
statutes and regulations should not be relied upon as an exhaustive review of
all matters affecting Kelley's operations.
 
  TRANSPORTATION AND PRODUCTION
 
  Transportation and Sale of Natural Gas. Prior to January 1, 1993, various
aspects of Kelley's natural gas operations were subject to regulations by the
FERC under the Natural Gas Act of 1938 (the "NGA") and the NGPA with respect
to "first sales" of natural gas, including price controls and certificate and
abandonment authority regulations. However, as a result of the enactment of
the Decontrol Act, the remaining "first sales" restrictions imposed by the NGA
and the NGPA terminated on January 1, 1993.
 
  The FERC regulates interstate natural gas pipeline transportation rates and
service conditions, which affect the marketing of gas produced by Kelley, as
the revenues received by Kelley for sales of such natural gas. Since the
latter part of 1985, the FERC has adopted policies intended to make natural
gas transportation more accessible to gas buyers and sellers on an open and
nondiscriminatory basis. The FERC's most recent action in this area, Order No.
636, reflected the FERC's finding that, under the then-existing regulatory
structure, interstate pipelines and other gas merchants, including producers,
did not compete on a "level playing field" in selling gas. Order No. 636
instituted individual pipeline services restructuring proceedings, designed
specifically to "unbundle" those services provided by many interstate
pipelines (for example, transportation, sales and storage) so that buyers of
natural gas may secure supplies and delivery services from the most economical
source, whether interstate pipelines or other parties. The FERC has issued
final orders in the restructuring proceedings, and a number of pipelines have
filed tariff sheets reflecting refinements in the implementation of Order No.
636 following three years of operation under the program. In addition, the
FERC has announced its intention to reexamine certain of its transportation
related policies, including the appropriate manner in which interstate
pipelines release transportation capacity under Order No. 636 and, more
recently, the price that shippers can charge for released capacity. The FERC
also has issued a new policy regarding the use of nontraditional methods of
setting rates for interstate gas pipelines in certain circumstances as
alternatives to cost-of-service based rates. A number of pipelines have
obtained FERC authorization to charge negotiated rates as one such
alternative.
 
  Although the FERC's actions, such as Order No. 636, do not regulate gas
producers such as Kelley, these actions are intended to foster increased
competition within all phases of the natural gas industry. To date, the FERC's
pro-competition policies have not materially affected Kelley's business or
operations. On a prospective basis, however, such orders may substantially
increase the burden on the producers and transporters to nominate and deliver
on a daily basis a specified volume of natural gas. Producers and transporters
which deliver deficient volume or volumes in excess of such daily nominations
could be subject to additional charges by the pipeline carriers.
 
  The United States Court of Appeals for the District of Columbia Circuit has
affirmed the Commission's Order No. 636 restructuring rule and remanded
certain issues for further explanation or clarification. Numerous
 
                                      56
<PAGE>
 
petitions seeking judicial review of the individual pipeline restructuring
orders are currently pending in the United States Court of Appeals for the
District of Columbia Circuit. It is not possible to predict what, if any,
effect the order on remand or the Court's decision in the individual pipeline
cases will have on the Company. The Company does not believe, however, that it
will be affected any differently than other gas producers or marketers with
which it competes.
 
  Additional proposals and proceedings that might affect the natural gas
industry are considered from time to time by Congress, the FERC, state
regulatory bodies and the courts. Kelley cannot predict when or if any such
proposals might become effective or their effect, if any, on Kelley's
operations. The natural gas industry historically has been very heavily
regulated; thus there is no assurance that the less stringent regulatory
approach recently pursued by the FERC and Congress will continue indefinitely
into the future.
 
  Transportation and Sale of Crude Oil. Sales of crude oil and condensate can
be made by Kelley at market prices not subject at this time to price controls.
The price that Kelley receives from the sale of these products is affected by
the cost of transporting the products to market. Commencing in October 1993,
the FERC issued a series of orders (Order Nos. 561 and 561-A) in which it
revised its regulations governing the rates that may be charged by oil
pipelines. The new rules, which became effective January 1, 1995, provide a
simplified, generally applicable method for regulating such rates by use of an
index for setting rate ceilings. In certain circumstances, the new rules
permit oil pipelines to establish rates using traditional costs of service and
other methods of ratemaking. On October 28, 1994, the FERC issued two separate
Orders (Nos. 571 and 572), which adopt additional regulations governing rates
that an oil pipeline may be authorized to charge. Order No. 571 authorizes a
pipeline to implement cost-of-service based rates, provided it can demonstrate
that there is a substantial divergence between the actual costs experienced by
the carrier and the indexed rate that the pipeline is directed to charge under
Order No. 561. In Order No. 572, the FERC adopted regulations that authorize a
pipeline to charge market-based rates, provided it can demonstrate that it
lacks significant market power in the market(s) in which it proposes to charge
such rates. These rules have been affirmed by the U.S. Court of Appeals for
the District of Columbia Circuit. The effect that these new rules may have on
moving Kelley's liquid products to market cannot yet be determined.
 
  Regulation of Production. The production of oil and natural gas is subject
to regulation under a wide range of state and federal statutes, rules, orders
and regulations. State and federal statutes and regulations require permits
for drilling operations, drilling bonds and reports concerning operations.
Most states in which Kelley owns and operates properties have regulations
governing conservation matters, including provisions for the unitization or
pooling of oil and natural gas properties, the establishment of maximum rates
of production from oil and natural gas wells and the regulation of the
spacing, plugging and abandonment of wells. Many states also restrict
production to the market demand for oil and natural gas and several states
have indicated interest in revising applicable regulations. The effect of
these regulations is to limit the amount of oil and natural gas Kelley can
produce from its wells and to limit the number of wells or the locations at
which Kelley can drill. Moreover, each state generally imposes an ad valorem,
production or severance tax with respect to production and sale of crude oil,
natural gas and gas liquids within its jurisdiction.
 
  ENVIRONMENTAL REGULATIONS
 
  General. Various federal, state and local laws and regulations governing the
discharge of materials into the environment, or otherwise relating to the
protection of the environment, affect Kelley's operations and costs. In
particular, Kelley's exploration, development and production operations, its
activities in connection with storage and transportation of crude oil and
other liquid hydrocarbons and its use of facilities for treating, processing
or otherwise handling hydrocarbons and wastes therefrom are subject to
stringent environmental regulation. As with the industry generally, compliance
with existing regulations increases Kelley's overall cost of business. 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 gas exploration wastes and capital costs to construct,
maintain and upgrade equipment and facilities.
 
                                      57
<PAGE>
 
  The Company incurs some expenses related to the disposition of drilling
fluids and produced waters, but these costs do not constitute a material
expense to the Company. The Company anticipates that it will incur additional
expenses related to compliance with environmental regulations at the time it
abandons a producing property or lease. The amount of these costs will vary,
but based on the Company's experience, the amount and timing of these costs
should not materially increase the Company's overall cost of business. In
addition, the Company does not anticipate that it will be required to make any
significant capital expenditures to comply with current environmental
requirements.
 
  Environmental regulations historically have been subject to frequent change
by regulatory authorities, and the Company is unable to predict the ongoing
cost to Kelley to comply 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 Kelley's
competitive position because its competitors are similarly affected. A
discharge of hydrocarbons or hazardous substances into the environment could
subject Kelley to substantial expense, including both the cost to comply with
applicable regulations pertaining to the remediation of releases of hazardous
substances into the environment and claims by neighboring landowners and other
third parties for personal injury and property damage. Kelley maintains some
insurance, which may provide some protection against some 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 Kelley from
substantial expense.
 
  Water. The Oil Pollution Act (the "OPA") was enacted in 1990 and amends
provisions of the Federal Water Pollution Control Act of 1972 (the "FWPCA")
and other statutes as they pertain to prevention and response to oil spills.
The OPA subjects owners of facilities to strict, joint and potentially
unlimited liability for removal costs and certain other consequences of an oil
spill, where such spill is into navigable waters, along shorelines or in the
exclusive economic zone. In the event of an oil spill into such waters,
substantial liabilities could be imposed upon the Company. States in which
Kelley operates also have enacted similar laws. Regulations are being
developed under both the OPA and state laws that may impose additional
regulatory burdens on the Company.
 
  The FWPCA imposes restrictions and strict controls regarding the discharge
of produced waters and other oil and gas wastes into navigable waters. These
controls have become more stringent over the years, and it is probable that
additional restrictions will be imposed in the future. Permits must be
obtained to discharge pollutants into state and federal waters. The FWPCA
provides for civil, criminal and administrative penalties for any unauthorized
discharges of oil and other hazardous substances in reportable quantities and,
along with the OPA, imposes substantial potential liability for the costs of
removal, remediation and damages. State laws for the control of water
pollution also provide varying civil, criminal and administrative penalties
and impose liabilities in the case of a discharge of petroleum or its
derivatives, or other hazardous substances, into state waters. In addition,
the Environmental Protection Agency ("EPA") has promulgated regulations that
require many oil and gas production operations to obtain permits to discharge
storm water runoff. The Company believes that compliance with existing permits
and with foreseeable new permit requirements will not have a material adverse
effect on the Kelley's financial condition or results of operations.
 
  Air Emissions. The operations of Kelley are subject to the Federal Clean Air
Act and comparable state and local statutes. The Company believes that
Kelley's operations are in substantial compliance with such statutes in all
states in which it operates.
 
  Amendments to the Federal Clean Air Act enacted in 1990 require or will
require most industrial operations in the United States to incur capital
expenditures in order to meet air emission control standards developed by the
EPA and state environmental agencies. Although no assurances can be given, the
Company believes implementation of such amendments will not have a material
adverse effect on Kelley's financial condition or results of operations.
 
 
                                      58
<PAGE>
 
  Solid Waste. The Federal Resource Conservation and Recovery Act ("RCRA") is
the principal federal statute governing the treatment, storage and disposal of
hazardous wastes. RCRA imposes stringent operating requirements (and liability
for failure to meet such requirements) on a person who is either a "generator"
or "transporter" of hazardous waste or an "owner" or "operator" of a hazardous
waste treatment, storage or disposal facility. At present, RCRA includes a
statutory exemption that allows oil and gas exploration and production wastes
to be classified as non-hazardous waste. A similar exemption is contained in
many of the state counterparts to RCRA. As a result, Kelley is not required to
comply with a substantial portion of RCRA's requirements because Kelley's
operations generate minimal quantities of hazardous wastes. However, at
various times in the past, proposals have been made to rescind the exemption
that excludes oil and gas exploration and production wastes from regulation as
hazardous waste under RCRA. Repeal or modification of this exemption by
administrative, legislative or judicial process, or through changes in
applicable state statutes, would increase the volume of hazardous waste to be
managed and disposed of by Kelley. Hazardous wastes are subject to more
rigorous and costly disposal requirements than are non-hazardous wastes. Such
changes in the regulations may result in additional capital expenditures or
operating expenses by Kelley.
 
  Superfund. The Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA"), also known as "Superfund", imposes liability,
without regard to fault or the legality of the original act, on certain
classes of persons that contributed to the release of a "hazardous substance"
into the environment. These persons include the "owner" or "operator" of the
site and companies that disposed or arranged for the disposal of the hazardous
substances found at the site. CERCLA also authorizes the EPA and, in some
instances, third parties to act in response to threats to the public health or
the environment and to seek to recover from the responsible classes of persons
the costs they incur. In the course of its ordinary operations, Kelley may
generate waste that may fall within CERCLA's definition of a "hazardous
substance". Kelley may be jointly and severally liable under CERCLA or under
analogous state laws for all or part of the costs required to clean up sites
at which such wastes have been disposed.
 
  Kelley 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 gas. Although Kelley has utilized operating and disposal
practices that were standard in the industry at the time, hydrocarbons or
other wastes may have been disposed of or released on or under the properties
owned or leased by Kelley 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 Kelley's
control. These properties and wastes disposed thereon may be subject to
CERCLA, RCRA and analogous state laws. Under such laws, Kelley could be
required to remove or remediate previously disposed wastes (including wastes
disposed of or released by prior owners or operators), to clean up
contaminated property (including contaminated groundwater) or to perform
remedial plugging operations to prevent future contamination.
 
TITLE TO PROPERTIES
 
  Kelley's properties, in addition to being mortgaged to secure the New Credit
Facility, are subject to royalty interests, liens incident to operating
agreements, liens for current taxes and other customary burdens, including
other mineral encumbrances and restrictions. The Company does not believe that
any mortgage, lien or other burden materially interferes with the use of such
properties in the operation of Kelley's business.
 
  The Company believes that Kelley has satisfactory title to or rights in all
of its producing properties. As is customary in the oil and natural gas
industry, minimal investigation of title is made at the time of acquisition of
undeveloped properties. Title investigation is made, and title opinions of
local counsel are generally obtained before commencement of drilling
operations or at least in connection with the preparation of division orders
when production is obtained and the revenues therefrom are allocated.
 
 
                                      59
<PAGE>
 
EMPLOYEES
 
  As of November 30, 1996, Kelley had 70 full-time employees. Kelley's staff
includes employees experienced in geology, geophysics, petroleum engineering,
land acquisition and management, finance and accounting. None of Kelley's
employees is represented by a union. Kelley has never experienced an
interruption in its operations from any kind of labor dispute, and its working
relationships with its employees are satisfactory.
 
LEGAL PROCEEDINGS
 
  Following Kelley Oil's announcement of the initial proposal for the
Consolidation in August 1994, four separate lawsuits were filed against Kelley
Oil and its directors relating to the Consolidation and the 1991 DDP Exchange.
In November 1994, Kelley Oil entered into a memorandum of understanding with
the plaintiffs in three of the lawsuits, providing for a proposed settlement
based on the revised Consolidation proposal negotiated by a special committee
of Kelley Oil's nonmanagement directors and the settling plaintiffs. A
stipulation and agreement of compromise, settlement and release reflecting the
terms of the proposed settlement was filed in the United States District Court
for the Southern District of Texas on November 23, 1994. At a hearing held on
the same date, the court approved the consolidation of all four lawsuits and
the certification of a unitholder class requested by the settling parties. On
March 3, 1995, following a hearing on the fairness of the settlement, the
court entered a final order approving the settlement, dismissing the
consolidated lawsuits with prejudice and reducing the award of attorneys' fees
and disbursements contemplated by the stipulation to $1.5 million, payable $.3
million in cash and the balance in Common Stock of the Company. An appeal
subsequently filed by the nonsettling plaintiff is currently pending in the
United States Court of Appeals for the Fifth Circuit. Although the Company
believes approval of the settlement and dismissal of the lawsuits should be
upheld, it could be required, if not upheld, to litigate certain claims
alleged in the lawsuits, including the adequacy and fairness of the exchange
ratios for the Consolidation.
 
  Kelley is involved from time to time in various claims and lawsuits
incidental to its business. In the opinion of management, the ultimate
liability thereunder, if any, will not have a material effect on the financial
condition of Kelley.
 
                                      60
<PAGE>
 
                                COMPANY HISTORY
 
THE CONSOLIDATION
 
  The Company was formed in 1994 to consolidate the equity ownership of Kelley
Partners and Kelley Oil. Prior to the Consolidation in 1994, drilling
activities were conducted jointly by Kelley Partners and DDPs sponsored by
Kelley Oil for that purpose. Historically, Kelley Oil (the managing general
partner of Kelley Partners) participated proportionately in these operations,
with Kelley Partners retaining one-third of its working interest in each
prospect and assigning drilling rights for the balance of its interest to a
DDP. In addition to serving as managing general partner of each DDP, Kelley
Oil purchased for its own investment account all units in DDPs that were not
subscribed preemptively by other investors in Kelley Partners. In the
Consolidation, 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 ("Public Preferred
Stock") and 2.2 million shares of cumulative convertible preferred stock
("ESOP Preferred Stock") held by its Employee Stock Ownership Plan (the
"ESOP"). As a result of the Consolidation, Kelley Oil became a wholly-owned
subsidiary of the Company, and Kelley Partners became a 99.99%-owned
subsidiary partnership. The Consolidation was treated as a purchase of the
public unitholders' interests in Kelley Partners by the Company for financial
accounting purposes. Accordingly, historical financial and reserve information
presented in this Prospectus thereto reflects Kelley Oil's historical results
on a stand-alone basis prior to the Consolidation, with the results of
Kelley's combined operations recorded thereafter.
 
THE CONTOUR TRANSACTION
 
   In November 1995, the Company reported that it expected to be substantially
capital constrained by the middle of 1996 due to low levels of internally
generated cash flow and borrowing restrictions. At that time, Kelley
implemented an immediate reduction in its drilling activities and aggressively
pursued outside capital in the form of an equity placement, merger or sale of
the Company. Following discussions with potential acquirors, the Company
entered into the Contour Agreements in January 1996, which provided for a two-
stage equity investment of $75 million in the Company by Contour. On February
15, 1996, the first stage of the equity investment was completed through
Contour's $48 million purchase of newly issued shares of Common Stock
(representing on such date 49.8% of the voting shares of the Company) (the
"Contour Transaction"). Additionally, the Company entered into an option
agreement (the "Contour Option"), under which Contour has committed to provide
the Company with $27 million in additional equity financing through an option
to purchase 27 million shares (the "Maximum Option Number") of Common Stock
upon satisfaction of certain conditions, including the absence of any Company
debt repurchase or redemption obligations as a result of the purchase (a "Debt
Event"), but in no event later than January 2000. A Debt Event would occur
upon (i) a "Change of Control" as defined in the 13 1/2% Indenture, (ii) a
"Change in Control" as defined in the indenture for the Company's 7 7/8%
Convertible Subordinated Notes due 1999 (the "7 7/8% Notes") or (iii) a
"Redemption Event" as defined in the indenture for the Company's 8 1/2%
Convertible Subordinated Debentures due 2000 (the "8 1/2% Debentures"). A Debt
Event with respect to either series of notes or the 8 1/2% Debentures would
entitle each holder of the affected securities to require the repurchase or
redemption of the holder's securities. Contour is required to exercise the
Contour Option for the Maximum Option Number within 30 days after it concludes
in its sole discretion that a Debt Event would not occur as a result of the
purchase but in no event later than January 2000. While the exercise of the
Contour Option would not cause a Debt Event under the indenture for the 8 1/2%
Debentures, it would require waivers or consents from the holders of a
majority in aggregate principal amount of the 7 7/8% Notes. The Refinancing
eliminated the possibility of a Debt Event as to the 13 1/2% Notes.
 
 
                                      61
<PAGE>
 
  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 named by him, (iii) reduced the size of its
Board to seven members and reconstituted the Board with three continuing
directors and four designees of Contour and (iv) replaced its credit facility.
Proceeds from the Contour Transaction, after repayment of bank debt, plus
funds available under its credit facility have permitted Kelley to continue
drilling operations and permitted it to pursue acquisition opportunities
needed to execute its business strategy for replacing its production and
expanding its reserves. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations--General."
 
OTHER
 
  In March 1996, Kelley Partners was merged into the Company (the "Partnership
Merger") as part of ongoing efforts to streamline operations and reduce costs.
Prior to the Partnership Merger, Kelley Partners had outstanding 8 1/2%
Debentures in the aggregate principal amount of $26.9 million and 7 7/8% Notes
in the aggregate principal amount at maturity of $34.4 million. Under the
terms of the Consolidation, the 8 1/2% Debentures and 7 7/8% Notes became
convertible into the Company's Common Stock or a combination of its Common
Stock and Public Preferred Stock instead of units in Kelley Partners based on
the exchange ratios for the units in the Consolidation. In connection with the
Partnership Merger, the two outstanding subordinated debt issues became direct
obligations of the Company.
 
  In March 1996, the Special Conversion Right for the Public Preferred Stock
was triggered by the Contour Transaction. Under the Special Conversion Right,
the conversion price of the Public Preferred Stock was reduced to $4.00 for a
period of 45 days ended April 25, 1996. A total of .7 million shares of Public
Preferred Stock were tendered pursuant to the Special Conversion Right,
resulting in the issuance of 4.4 million shares of Common Stock and a
reduction in the outstanding Public Preferred Stock to 1.7 million shares as
of June 30, 1996. Although dividends on both classes of preferred stock were
suspended in January 1996, the decrease in outstanding Public Preferred Stock
and the conversion of the ESOP Preferred Stock will reduce future dividend
arrearages. Although the Board of Directors of the Company has made no
determination regarding the payment of dividend arrearages on the Public
Preferred Stock, and while any such payments must not be prohibited under
applicable corporate law, the New Credit Facility and the Indenture are
expected to permit the Company to make a one-time payment of such dividend
arrearages on or before January 31, 1997. However, the New Credit Facility
prohibits the payment of future preferred dividends.
 
  The Company had four outstanding series of ESOP Preferred Stock, which
ranked junior in dividend and liquidation rights to the Public Preferred
Stock. In June 1996, each of the outstanding 1.9 million shares of ESOP
Preferred Stock was redeemed for one share of the Company's Common Stock.
 
                                      62
<PAGE>
 
                                  MANAGEMENT
 
DIRECTORS AND EXECUTIVE OFFICERS
 
  Current Directors and Executive Officers. In February 1996, upon the closing
of the Contour Transaction, John F. Bookout, President of Contour, was
appointed as Chairman of the Board, President and Chief Executive Officer of
the Company. In connection with the Contour Transaction, the Board of
Directors appointed Dallas D. Laumbach, William C. Rankin and, on July 16,
1996, Thomas E. Baker to senior executive positions with the Company, and the
Board was reconstituted with three continuing directors and four designees of
Contour.
 
  Set forth below are the names, ages and positions of the current executive
officers and directors of the Company. All directors are elected for a term of
one year and serve until their successors are duly elected and qualified. All
executive officers hold office until their successors are duly appointed and
qualified.
 
<TABLE>
<CAPTION>
                                                                               OFFICER OR
                                                                               DIRECTOR OF
                                                                               THE COMPANY
   NAME                  AGE                     POSITION                         SINCE
   ----                  ---                     --------                      -----------
<S>                      <C> <C>                                               <C>
John F. Bookout.........  73 President, Chief Executive Officer and a Director    1996
Thomas E. Baker.........  65 General Counsel and Corporate Secretary              1996
Dallas D. Laumbach......  59 Senior Vice President--Exploration and Production    1996
William C. Rankin.......  47 Senior Vice President and Chief Financial Officer    1996
Charles L. Winn, Sr. ...  68 Senior Vice President--Exploration                   1991
William E. Albrecht.....  45 Vice President--Engineering and Development          1996
Lawrence G. Marble......  43 Controller and Principal Accounting Officer          1996
Stephen M. Smith........  45 Treasurer                                            1995
John J. Conklin, Jr. ...  66 Director                                             1993
Ralph P. Davidson.......  69 Director                                             1993
William J. Murray.......  81 Director                                             1984
Ogden M. Phipps.........  57 Director                                             1996
Michael B. Rothfeld.....  49 Director                                             1996
Ward W. Woods...........  55 Director                                             1996
</TABLE>
 
  John F. Bookout joined the Company as Chairman of the Board, President and
Chief Executive Officer in February 1996 upon completion of the Contour
Transaction. He served as Chairman of the Board of Contour since its inception
in 1993. Before joining Contour as a founder, Mr. Bookout served in positions
of increasing responsibility for 38 years at Shell Oil Company, starting in
1950 as a geologist and culminating from 1976 through June 1988 as President,
Chief Executive Officer and a director. From 1988 through 1993, he served as a
member of the Supervisory Board of Royal Dutch Petroleum. He currently serves
on the board of directors of McDermott International Inc., J. Ray McDermott,
S.A. and The Investment Company of America as well as the board of trustees of
the United States Counsel for International Business and various civic and
educational bodies. Mr. Bookout received Bachelor's and Master's degrees in
geology from the University of Texas.
 
  Thomas E. Baker, an attorney, joined the Company in July 1996 as General
Counsel and Corporate Secretary. His experience includes 28 years at Shell Oil
Company, where he served as a Corporate Secretary from 1984 until his
retirement in 1991. From 1991 through 1996, Mr. Baker was engaged in a private
consulting practice. Mr. Baker received a B.S. in accounting from the
University of Notre Dame, and an LL.B. and an LL.M. from Georgetown University
and an LL.M. from New York University.
 
  Dallas D. Laumbach has served as Senior Vice President--Exploration and
Production of the Company since February 1996 and has served concurrently as
President of Concorde Gas, Inc. since August 1996. He previously served as
Senior Vice President of Contour since December 1993. Before joining Contour,
Mr. Laumbach served in positions of increasing responsibility for 24 years at
Shell Oil Company, concluding as Manager--Business Development in Shell's Head
Office. He received a Bachelor's degree in mechanical
 
                                      63
<PAGE>
 
engineering from Iowa State University, a Master's degree in mechanical
engineering from the University of New Mexico and a Ph.D. in mechanical
engineering from Massachusetts Institute of Technology.
 
  William C. Rankin has served as Senior Vice President and Chief Financial
Officer of the Company since February 1996. He previously served as Vice
President and Chief Financial Officer of Contour commencing in March 1994,
after serving eight years as a senior financial officer of Hadson Corporation,
including the last four years as Senior Vice President and Chief Financial
Officer of Hadson Energy Resources Corporation. Mr. Rankin received a
Bachelor's degree in accounting from the University of Arkansas.
 
  Charles L. Winn, Sr. joined the Company in October 1991 and has served as
Senior Vice President since October 1995 and as a Vice President since
February 1993. From 1973 until joining the Company, he was the President and
principal shareholder of Wincan, Inc., which was a private company engaged in
the geophysical interpretation of oil and gas prospects through the
application of advanced seismic techniques and was acquired by Kelley Oil in
1991. Mr. Winn studied mechanical engineering at Texas Tech University.
 
  William E. Albrecht has served as Vice President--Production of the Company
since February 1996. He joined Contour in October 1993 as a Vice President
after serving for one year in the Corporate Engineering Group at Enron Oil &
Gas Company. During 1991 and 1990, Mr. Albrecht served as Manager of
Acquisitions for Pacific Enterprises Oil Company and Hadson Energy Resources
Corporation, respectively. Mr. Albrecht received a Bachelor's degree in
engineering from the U.S. Military Academy at West Point and a Master's degree
in systems management from the University of Southern California.
 
  Lawrence G. Marble has served as Controller and Principal Accounting Officer
of the Company since April 1996. Prior to joining the Company, he served as
Controller for Energy Development Corporation for seven years, and for the
previous thirteen years held various accounting management positions with
Total Minatome Corporation, CSX Oil & Gas Corporation and Arthur Andersen &
Co. Mr. Marble is a certified public accountant and received his Bachelor's
degree in accounting from Texas A&M University.
 
  Stephen M. Smith has served as Treasurer of the Company since November 1995.
Prior to joining the Company, Mr. Smith served as Vice President--Energy at
Bank One, Texas, N.A. for more than five years. He received a Bachelor's
degree in finance from the University of Texas and a Master's degree in
finance from the University of Houston.
 
  John J. Conklin, Jr. has served as a director of the Company since November
1993. Mr. Conklin has been a private investor since his retirement in 1989 as
a senior partner of Conklin, Cahill & Co., a member firm of the New York Stock
Exchange, where he was active for over 35 years. He has also served as a
member of the Board of Governors of the New York Stock Exchange, the Board of
Directors of the New York Futures Exchange and the National Market Advisory
Board.
 
  Ralph P. Davidson served as Chairman of the Board of the Company from
October 1995 through February 1996 and has served as a director of the Company
since November 1993. Mr. Davidson served since 1993 as the Chairman of Capital
Publishing Company, the publisher of Washington Monthly, a journal of
political commentary, while also providing consulting services to nonprofit
organizations since 1991 as President of Davidson Associates. From 1980
through 1987, he was Chairman of the Board of Time, Inc., where he spent 21
years with Time Magazine in various executive capacities. Mr. Davidson is a
director of First Interstate Bancorp and a member of the Board of Trustees of
Phoenix House and the National Council for Adoption.
 
  William J. Murray has served as a director of the Company since March 1984.
Mr. Murray has been an independent petroleum consultant for more than the past
five years. He served on the Texas Railroad Commission for 16 years, during
six of which he served as Chairman. Mr. Murray currently serves on a number of
industry committees, including as Chairman of the Industry Advisory Committee
on Natural Gas Ratable Take and Chairman of the Industry Voluntary Allocation
Committee.
 
 
                                      64
<PAGE>
 
  Ogden M. Phipps has served as a director of the Company since February 1996.
He was Chairman of the Board of Bessemer Securities Corporation ("BSC") from
1982 through 1994 and of The Bessemer Group, Incorporated ("BGI") from 1991
through 1994. BSC is the principal limited partner of Bessemer Holdings, L.P.
("Bessemer"). Mr. Phipps continues to serve as a director of BSC and BGI. He
also serves as a director of Stant Corporation and several private companies
and an officer and director of several non-profit organizations.
 
  Michael B. Rothfeld has served as a director of the Company since February
1996. Since 1989, he has been the sole stockholder and president of
corporations that serve as a general partner or manager of the general partner
of Bessemer and other investment partnerships. He is also the sole stockholder
and president of a corporation that is a general partner of Bessemer Partners
& Co. From June 1989 through June 1993, Mr. Rothfeld was also a Managing
Director of BSC. He is Chairman of the Board of Graphic Controls Corporation
and a director of several private companies.
 
  Ward W. Woods has served as a director of the Company since February 1996.
Since 1989, he has been the sole stockholder and president of corporations
that serve as the managing general partner or principal manager of the general
partner of Bessemer and other investment partnerships. He is also the sole
stockholder and president of a corporation that is the managing general
partner of Bessemer Partners & Co. Mr. Woods is the President and Chief
Executive Officer of BSC, which he joined in 1989. He is Chairman of the Board
of Stant Corporation, BCP/Essex Holdings, Inc. and a director of Freeport-
McMoRan Copper & Gold Inc., Boise Cascade Corporation, Graphic Controls
Corporation and several private companies.
 
BOARD AND COMMITTEES
 
  During 1996, the Board was comprised of (i) Messrs. Conklin, Davidson and
Murray, who remained on the Board after the Contour Transaction and (ii) Fair
Colvin, Jr., Bromley DeMeritt, Frank G. Lyon, W. Matt Ralls and Alan N.
Sidnam, who resigned in accordance with the agreement covering the Contour
Transaction. See "--Directors and Executive Officers".
 
  The Board has established an Audit Committee and a Compensation Committee.
During the first months of 1996, both committees were comprised Messrs.
Conklin, Davidson, Lyon, Murray and Sidnam. In April 1996, the Board made new
assignments for these Committees and established a Nominating Committee. The
new assignments are as follows:
 
<TABLE>
<CAPTION>
           AUDIT                  COMPENSATION              NOMINATING
         COMMITTEE                  COMMITTEE                COMMITTEE
         ---------                ------------              ----------
<S>                          <C>                     <C>
Ralph P. Davidson--Chairman  Ward W. Woods--Chairman Ogden M. Phipps--Chairman
John J. Conklin, Jr.         John J. Conklin, Jr.    William J. Murray
Michael B. Rothfeld          Ralph P. Davidson       Ward W. Woods
                             Ogden M. Phipps
</TABLE>
 
  The Audit Committee is charged with various duties relating to the Company's
financial reporting obligations. These responsibilities include recommending
the appointment of independent auditors to the Board, reviewing the
compensation of the auditors, reviewing the scope and results of the annual
audit performed by the independent auditors, assuring that proper guidelines
are established for the dissemination of financial information, conferring
with the auditors to assure the adequate training and supervision of the
Company's accounting personnel, meeting periodically with the auditors, the
Board and senior management to ensure the adequacy of internal controls and
reporting functions and reviewing the Company's consolidated financial
statements. The Audit Committee held one meeting during 1996, with all members
of the Committee participating.
 
  The Compensation Committee has the authority to review the compensation
policies of the Company, consider and recommend to the Board succession plans
for senior management and administer and make awards under the Company's
employee benefit plans. The Compensation Committee held two meetings during
1996, with all members of the Committee participating.
 
                                      65
<PAGE>
 
  The Nominating Committee was formed in 1996 to evaluate the size and
composition of the Board and establish guidelines for director qualifications.
Any recommendations by stockholders will be considered if received within 120
days prior to the anniversary date of the last annual meeting of stockholders.
 
COMPENSATION OF DIRECTORS
 
  The Company's nonmanagement directors receive compensation of $3,750 on a
quarterly basis and $1,000 per committee meeting attended.
 
COMPENSATION OF NAMED EXECUTIVE OFFICERS
 
  The following table sets forth the total remuneration paid during 1996, 1995
and 1994 to the two individuals who served as the Chief Executive Officer of
the Company during 1996 and the Company's four other most highly compensated
executive officers during 1996 (the "Named Executive Officers"). Compensation
for 1996 reflects full-year amounts estimated as of December 15, 1996.
 
                          SUMMARY COMPENSATION TABLE
 
<TABLE>
<CAPTION>
                                                           LONG TERM
                                  ANNUAL COMPENSATION    COMPENSATION        ALL OTHER
                                  ---------------------------------------   OPTION/SAR
NAME AND PRINCIPAL POSITION  YEAR  SALARY   BONUS(1)  OTHER(2) AWARDS (#) COMPENSATION(3)
---------------------------  ---- --------- ------------------ ---------- ---------------
<S>                          <C>  <C>       <C>       <C>      <C>        <C>
John F. Bookout(4)......     1996 $ 700,000 $     --  $   --         --       $ 2,667
Chairman, President and
 CEO                         1995       --        --      --         --           --
                             1994       --        --      --         --           --
Fair Colvin, Jr.(4).....     1996   171,875   150,000   7,200        --       144,792(5)
Former CEO; Former Pres-
 ident                       1995   275,000       --      --     300,000       22,500
of Concorde Gas, Inc.        1994   275,000   137,500     --         --        24,247
Dallas D. Laumbach(4)...     1996   166,250       --      --     862,500        3,800
Senior Vice President--      1995       --        --      --         --           --
Exploration and Produc-
 tion                        1994       --        --      --         --           --
William C. Rankin(4)....     1996   144,375       --      --     862,500        3,300
Senior Vice President
 and Chief                   1995       --        --      --         --           --
Financial Officer            1994       --        --      --         --           --
Charles L. Winn, Sr. ...     1996   160,000       --   13,200        --         3,200
Senior Vice President--      1995   145,833       --      --     150,000       21,875
Exploration                  1994   143,000       --      --         --        23,115
William E. Albrecht(4)..     1996   109,374       --      --     775,000        2,500
Vice President--Engi-
 neering                     1995       --        --      --         --           --
and Development              1994       --        --      --         --           --
</TABLE>
--------
(1) Bonus payments in each year reflect awards for performance.
(2) Perquisites and other benefits did not exceed 10% of any named officer's
    total annual salary and bonus.
(3) 1996 amounts include matching contributions by the Company to the named
    executive officer's 401(k) account. 1995 and 1994 amounts reflect the
    portion of contributions to the ESOP attributable to the named executive
    officers. Prior to 1996, the Company made annual contributions to the
    ESOP, on behalf of all employees, in an amount equal to 15% of their cash
    compensation up to a specified level. See "--Employee Benefit Plans--
    Section 401(k) and Employee Stock Ownership Plan".
(4) Mr. Colvin served as President and CEO from October 1995 through February
    1996. In February 1996, Mr. Bookout was appointed Chairman, President and
    CEO of the Company, Mr. Colvin remained President of Concorde Gas, Inc.,
    Mr. Laumbach was appointed Senior Vice President--Exploration and
    Production, Mr. Rankin was appointed Senior Vice President and Chief
    Financial Officer and Mr. Albrecht was appointed Vice President--
    Engineering and Development. In August 1996, Mr. Colvin retired from
    Kelley.
(5) Includes $103,125 paid to Mr. Colvin during 1996 pursuant to his Change of
    Control Agreement and $41,667 pursuant to a consulting agreement with the
    Company. See "Certain Transactions".
 
                                      66
<PAGE>
 
STOCK OPTIONS
 
  The Company maintains incentive stock option plans (collectively, the "ISO
Plans") adopted in 1987 (the "1987 Plan"), 1991 (the "1991 Plan"), 1995 (the
"1995 Plan") and 1996 (the "1996 Plan"), covering 500,000 shares, 500,000
shares, 1.5 million shares and 1.0 million shares, respectively, of Common
Stock. The Company also maintains a 1996 Nonqualified Stock Option Plan (the
"NSO Plan"), which was adopted in February 1996 in accordance with the terms
of the Contour Agreements and provides for the grant of options to purchase a
total of 2.5 million shares of Common Stock to new senior executives
designated by Mr. Bookout. See "Employee Benefit Plans--Stock Option Plans".
The following table sets forth information as of December 31, 1996, on stock
options held by the Named Executive Officers in 1996.
 
                AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR
                       AND FISCAL YEAR END OPTION VALUES
 
<TABLE>
<CAPTION>
                                                                    VALUE OF
                                                      NUMBER OF   UNEXERCISED
                                  SHARES             UNEXERCISED  IN-THE-MONEY
                                 ACQUIRED    VALUE   OPTIONS AT    OPTIONS AT
  NAME                          ON EXERCISE REALIZED YEAR END(1)  YEAR END(3)
  ----                          ----------- -------- -----------  ------------
<S>                             <C>         <C>      <C>          <C>
John F. Bookout................    None       N/A       None             N/A
Fair Colvin, Jr. ..............    None       N/A      300,000(1)     75,000(1)
Dallas D. Laumbach.............    None       N/A      862,500(2)  1,401,563(2)
William C. Rankin..............    None       N/A      862,500(2)  1,401,563(2)
Charles L. Winn, Sr. ..........    None       N/A      150,000(1)     37,000(1)
William E. Albrecht............    None       N/A      775,000(2)  1,259,375(2)
</TABLE>
--------
(1) All of the stock options are currently exercisable after giving effect to
    accelerated vesting of unvested options as a result of change of control
    provisions for options granted under the 1995 Plan, which were triggered
    by the Contour Transaction.
(2) None of the options are currently exercisable as a result of vesting
    provisions.
(3) Calculated utilizing the closing price of the Common Stock on the Nasdaq
    Stock Market on December 16, 1996.
 
  The following table provides information about options granted during 1996
under the NSO Plan to the Named Executive Officers.
 
                     OPTION/SAR GRANTS IN LAST FISCAL YEAR
<TABLE>
<CAPTION>
                                       INDIVIDUAL GRANTS
                         ---------------------------------------------
                                                                       POTENTIAL REALIZABLE VALUE
                                                                         VALUE AT ASSUMED ANNUAL
                          NUMBER OF    % OF TOTAL  EXERCISE               RATES OF STOCK PRICE
                          SECURITIES  OPTIONS/SARS OR BASE                  APPRECIATION FOR
                          UNDERLYING   GRANTED TO   PRICE                    OPTION TERM(1)
                         OPTIONS/SARS EMPLOYEES IN   (PER   EXPIRATION ---------------------------
  NAME                     GRANTED    FISCAL YEAR   SHARE)     DATE         5%           10%
  ----                   ------------ ------------ -------- ---------- ------------- -------------
<S>                      <C>          <C>          <C>      <C>        <C>           <C>
John F. Bookout.........       --          --         --          --             --            --
Fair Colvin, Jr. .......       --          --         --          --             --            --
Dallas D. Laumbach......   862,500        34.5%      1.00   2/15/2006      1,404,922     2,237,103
William C. Rankin.......   862,500        34.5%      1.00   2/15/2006      1,404,922     2,237,103
Charles L. Winn, Sr. ...       --          --         --          --             --            --
William E. Albrecht.....   775,000        31.0%      1.00   2/15/2006      1,262,393     2,010,150
</TABLE>
--------
(1) In accordance with SEC guidelines, the potential realizable value was
    calculated assuming that the market value of the underlying security
    appreciates in value from the date of grant to the end of the option term
    at the assumed rate noted in the table. Actual gains, if any, upon
    exercise of NSOs and sales of the underlying shares of Common Stock will
    be dependent on future performance and stock market conditions, which may
    not reflect the potential realizable values shown in the table.
 
                                      67
<PAGE>
 
EMPLOYEE BENEFIT PLANS
 
  Section 401(k) and Employee Stock Ownership Plan. The Company has converted
its ESOP into a Section 401(k) Plan (the "401(k) Plan"). All employees are
eligible to participate in the 401(k) Plan. The Company previously contributed
to the ESOP an annual amount equal to 15% of each employee's compensation (up
to a specified level) to enable the ESOP to purchase qualifying securities for
the accounts of employees. Qualifying securities were allocated to employees'
accounts in the ESOP in amounts that were proportionate to the ESOP's
repayment of borrowings incurred to purchase those securities, all of which
are currently allocated following repayment of ESOP borrowings in 1995.
 
  Employees become fully vested in their accounts in the 401(k) Plan after six
years of service. Prior to converting the ESOP into a Section 401(k) Plan, the
ESOP held Preferred Stock which the Board redeemed in exchange for the same
number of shares of Common Stock. Effective with the conversion of the ESOP
into a Section 401(k) Plan, participants have the opportunity to invest their
accounts in various mutual funds and in Common Stock. The Company matches
employees' contributions to the 401(k) Plan in an amount up to 6% of the
employee's salary.
 
  Stock Option Plans. The purpose of the ISO Plans and the NSO Plan is to
offer eligible employees of the Company and its subsidiaries an opportunity to
acquire or increase their proprietary interests in the Company and provide
additional incentive to contribute to its performance and growth. The ISO
Plans are designed to qualify under section 422 of the Code. Under the 1987
Plan, options were granted to purchase a total of 185,000 shares of common
stock of Kelley Oil at $1.10 per share during 1988 and 315,000 shares at $2.00
per share during 1989. Under the 1991 Plan, options were granted to purchase a
total of 219,000 shares of Kelley Oil's common stock at $7 5/8 per share
during 1991, 15,000 shares at $7.00 per share during 1993 and 266,000 shares
of Common Stock at prices ranging from $1 3/4 to $2 3/8 per share during 1995.
The options granted under the 1991 Plan with an exercise price of $7 5/8 per
share were repriced in 1995, to the extent then outstanding, at $4 1/8 per
share. Under the 1995 Plan, options to purchase a total of 1.5 million shares
of Common Stock were granted during 1995 at exercise prices ranging from $1
3/4 to $2 3/8 per share. In 1995, 1994 and 1993, options were exercised for a
total of 225,000, 66,000 and 58,000 shares, respectively, at prices from $1.10
to $7 5/8 per share.
 
  The exercise price for options granted under the ISO Plans is fixed by the
Compensation Committee of the Board at the fair market value of the Common
Stock at the time of the grant. Each option granted under the ISO Plans is
exercisable during the term of the optionee's employment and three years
thereafter for up to ten years from the date of grant. The exercise price for
options granted under the NSO Plan is $1.00 per share. The ISO Plans and NSO
Plan will terminate upon the earlier of (i) the date on which all shares
available for issuance have been issued upon the exercise of options granted
thereunder or (ii) ten years from the date of adoption or April 2001 in the
case of the 1996 Plan.
 
EMPLOYMENT AGREEMENTS
 
  In connection with the Contour Transaction, the Company entered into three-
year employment agreements with John F. Bookout, Dallas D. Laumbach, William
C. Rankin and William E. Albrecht at base salaries of $800,000, $190,000,
$165,000 and $125,000, respectively. Each of the agreements provides for a
lump sum severance payment if the covered executive is terminated without
cause, as defined in the agreements. The severance payment would be equal to
one year's compensation based on the salary and bonus rate at the time of
termination, except that Mr. Bookout would be entitled to a payment covering
the balance of the three year term. Each of the agreements provides for
various customary benefits and for indemnification of the covered executive
under certain conditions.
 
CHANGE OF CONTROL AGREEMENTS
 
  In November 1995, the Company entered into change of control agreements with
16 management and professional personnel, entitling them to severance benefits
in the event their employment with the Company is terminated under certain
circumstances following a change of control, as defined in the agreements. For
this
 
                                      68
<PAGE>
 
purpose, the Contour Transaction constituted a change of control. The
severance benefits amount to salary continuation for twelve months, based on
the employee's highest compensation rate during the two years prior to
termination, for all covered employees other than certain executive officers,
including Mr. Colvin and Mr. Winn, Sr., who were entitled upon termination of
employment to salary continuation for a period ranging from 18 months to 36
months, depending on the individual. The Company's change of control
agreements with six individuals were triggered upon their termination of
employment during 1996. In addition, Mr. Colvin's change of control agreement
was triggered upon his retirement from the Company in August 1996, which
requires total payments to Mr. Colvin over a three-year period aggregating
$825,000. See "Certain Transactions." The Company currently has outstanding
change of control agreements with certain management and professional
personnel, under which the Company would be obligated to pay up to an
aggregate of approximately $.9 million if the employment of these individuals
were terminated under certain circumstances within two years of the Contour
Transaction.
 
                                      69
<PAGE>
 
                            PRINCIPAL STOCKHOLDERS
 
NONMANAGEMENT OWNERSHIP
 
  The following table sets forth information as of September 30, 1996, with
respect to the persons known by the Company to own beneficially more than five
percent of any class of its capital stock.
 
<TABLE>
<CAPTION>
                          NAME AND ADDRESS              AMOUNT AND NATURE    PERCENTAGE
 TITLE OF CLASS         OF BENEFICIAL OWNER          OF BENEFICIAL OWNERSHIP  OF CLASS
 --------------         -------------------          ----------------------- ----------
<S>             <C>                                  <C>                     <C>
Common Stock    Contour Production Company L.L.C.(1)      48,000,000(1)        48.84%
                630 Fifth Avenue, 39th Floor
                New York, New York 10111
</TABLE>
--------
(1) Excludes 27.0 million shares of Common Stock subject to the Contour
    Option. Bessemer owns a majority of the membership interests in Contour.
    Based on a Statement on Schedule 13-D filed with the SEC, Contour and
    Bessemer are each deemed to beneficially own the shares of Common Stock
    held of record by Contour following the Closing of the Contour
    Transaction. As of November 30, 1996, those shares represented 47.98% of
    the Company's total voting power. JFB Squared, Ltd. and Bevairohn, Ltd.,
    partnerships controlled by John F. Bookout, Chairman, President and CEO of
    the Company, and three other investment partnerships having the same
    general partner as Bessemer own the remaining interests in Contour and may
    be deemed to beneficially own the Common Stock held by Contour. Contour
    has agreed, subject to certain limitations, to vote for the election of
    Mr. Bookout as a director of the Company.
 
MANAGEMENT OWNERSHIP
 
  The following table sets forth information as of September 30, 1996, with
respect to the Common Stock and Public Preferred Stock beneficially owned,
directly or indirectly, by each of the Company's directors, by the Named
Executive Officers and by all of its current directors and executive officers
as a group.
 
<TABLE>
<CAPTION>
                                                              SHARES
                                            SHARES              OF
                                              OF              PUBLIC
  NAME OF                                   COMMON  PERCENT  PREFERRED PERCENT
BENEFICIAL OWNER                           STOCK(1) OF CLASS   STOCK   OF CLASS
----------------                           -------- -------- --------- --------
<S>                                        <C>      <C>      <C>       <C>
John F. Bookout(2)........................     --     --         --      --
Fair Colvin, Jr. ......................... 117,627    .12        --      --
Dallas D. Laumbach........................     --     --         --      --
William C. Rankin.........................     --     --         --      --
Charles L. Winn, Sr. (3).................. 166,957    .17        --      --
William E. Albrecht.......................     --     --         --      --
John J. Conklin, Jr. .....................  71,037    .07        --      --
Ralph P. Davidson(4)...................... 122,862    .13      4,500     .26%
William J. Murray(5)......................  86,680    .09      2,000     .11
Ogden M. Phipps...........................     --     --         --      --
Michael B Rothfeld(2).....................     --     --         --      --
Ward W. Woods(2)..........................     --     --         --      --
All current directors and executive
 officers as a group (14 persons)......... 456,536    .46%     6,500     .37%
</TABLE>
--------
(1) Represents shares of Common Stock owned directly and indirectly as
    indicated below, exclusive of indirect beneficial ownership under the ISO
    Plans and the NSO Plan, which amount to 1.142 million shares and 2.5
    million shares, respectively.
(2) Excludes 48.0 million shares of Common Stock held by Contour, in which
    Messrs. Bookout, Rothfeld and Woods and partnerships controlled by Mr.
    Bookout have an indirect interest and as to which each of Messrs. Rothfeld
    and Woods have disclaimed beneficial ownership. Also excludes 27.0 million
    shares of Common Stock subject to the Contour Option.
(3) Includes 744 shares of Common Stock held by Mr. Winn's wife.
(4) Includes 122,253 shares of Common Stock held by Mr. Davidson's wife and
    609 shares of Common Stock and 500 shares of Public Preferred Stock held
    by his daughter.
(5) Includes 4,875 shares of Common Stock held in a pension trust and 2,000
    shares of Public Preferred Stock held in Mr. Murray's defined benefit
    pension plan.
 
 
                                      70
<PAGE>
 
                             CERTAIN TRANSACTIONS
 
  Kelley Oil was the managing general partner of Kelley Partners prior to the
merger of Kelley Partners into the Company in March 1996 and is the managing
general partner of DDPs sponsored prior to the Consolidation to conduct
development drilling operations on selected properties of the Company. Kelley
Oil was reimbursed by Kelley Partners and the DDPs for all appropriate
administrative and overhead expenses incurred in the administration of these
partnerships aggregating approximately $1.6 million net of intercompany
eliminations in 1995. Kelley Oil was also reimbursed by these affiliated
programs for direct costs incurred and advanced in connection with their lease
acquisition, exploration and development activities aggregating approximately
$6.1 million in 1995.
 
  Following the removal of David L. Kelley as Chairman, President and Chief
Executive Officer of the Company in October 1995, the Company entered into
consulting arrangements with Mr. Kelley at a monthly rate of $10,000 through
December 31, 1996. The Company also entered into a termination and settlement
agreement with Mr. Kelley, providing for (i) severance benefits to Mr. Kelley
aggregating $467,000 payable in monthly installments through December 31,
1996, (ii) transfer to Mr. Kelley of title to his corporate automobile with an
estimated value of $24,000, (iii) assumption of his unfunded subscriptions for
units in the 1992 DDP and the 1994 DDP in exchange for those units pursuant to
their respective partnership agreements, (iv) miscellaneous benefits with a
total estimated value of $75,000 and (v) an undertaking to pay Mr. Kelley an
amount equal to any federal income tax liability incurred by him as special
general partner of Kelley Partners and its operating partnership upon any
merger of Kelley Partners or its operating partnership into the Company, as a
result of which the Company paid Mr. Kelley $70,000 in connection with the
March 1996 merger of Kelley Partners into the Company.
 
  During 1995, the Company entered into change of control agreements with 16
employees entitling them to salary continuation for a period of 12 months,
except for Fair Colvin, Matt Ralls and Charles Winn, for whom the periods are
36 months, 24 months and 18 months, respectively, in the event their
employment is terminated under certain circumstances within two years after a
change of control, as defined in the agreements. See "Management--Change of
Control Agreements". During the first nine months of 1996, the Company's
change of control agreements with W. Matt Ralls, Amelia Johnson, Russell T.
Stevens, Fair Colvin and Regan Wood were triggered entitling them to salary
continuation aggregating $474,000, $89,250, $102,000, $825,000 and $152,000,
respectively. During the fourth quarter of 1996, the Company's change of
control agreements with Claude C. Crumrine and Stephen Stabile were triggered,
entitling them to salary continuation aggregating $109,220 and $85,000,
respectively. The Company's maximum liability under its change of control
agreements with remaining employees as of December 15, 1996, was approximately
$.9 million. In connection with Mr. Colvin's resignation, the Company entered
into a six-month consulting agreement with Mr. Colvin, which expires February
15, 1997 and pursuant to which he will be paid an aggregate consulting fee of
$50,000.
 
  In connection with the Contour Transaction, the Company entered into an
agreement (the "Advisory Agreement") with Bessemer Partners & Co. ("BPCO"), an
affiliate of Bessemer, providing for the engagement of BPCO to provide the
Company with financial advisory services for a term expiring at the end of
1998. Under the Advisory Agreement, BPCO has assisted the Company in arranging
a new credit facility and negotiating the related agreements and is assisting
the Company in restructuring its current capital structure. For its services
under the Advisory Agreement, BPCO received an advisory fee of $2 million at
the closing of the Contour Transaction and $500,000 in December 1996 and is
entitled to receive $500,000 per year payable in December 1997 and 1998. In
addition, BPCO is entitled to reimbursement of expenses incurred in connection
with rendering advisory services. The Company also has agreed to indemnify
BPCO and its affiliates against certain liabilities under the Advisory
Agreement.
 
  It is the policy of the Company to structure any transactions between the
Company and its officers, directors, principal stockholders or other
affiliates only on terms no less favorable to the Company than terms that
could be obtained on an arms-length basis from unrelated parties and only upon
approval by a majority of the Company's independent and disinterested
directors.
 
 
                                      71
<PAGE>
 
                       DESCRIPTION OF THE EXCHANGE NOTES
 
  The Exchange Notes will be issued as a separate series of notes under an
indenture (the "Indenture") dated as of October 15, 1996, among the Company,
Kelley Oil Corporation, Kelley Operating Company, Ltd. and United States Trust
Company of New York, as trustee (the "Trustee"). The Exchange Notes will be
senior unsecured obligations of the Company and are substantially identical
(including principal amount, interest rate, maturity and redemption rights) to
the Outstanding Notes for which they may be exchanged pursuant to this offer,
except for certain transfer restrictions and registration rights relating the
Outstanding Notes and except for certain interest provisions relating to those
rights. Under the terms of the Indenture, the covenants and events of default
will apply equally to the Exchange Notes and the Outstanding Notes, and the
Exchange Notes and the Outstanding Notes will be treated as one class for all
actions to be taken by the holders thereof and for determining their
respective rights under the Indenture. References to the Notes include the
Exchange Notes and the Outstanding Notes unless the context otherwise
requires. The Outstanding Notes were issued under the Indenture on October 29,
1996, in an aggregate principal amount of $125,000,000. The Indenture is
subject to and governed by the Trust Indenture Act of 1939, as amended (the
"Trust Indenture Act"). The following summaries of certain provisions of the
Indenture and the Registration Agreement do not purport to be complete and are
subject to, and are qualified in their entirety by reference to, all of the
provisions of the Indenture and the Registration Agreement, including the
definition of certain terms contained therein and those terms that are made a
part of the Indenture by reference to the Trust Indenture Act. Copies of the
Indenture and Registration Agreement have been filed as exhibits to the
Registration Statement of which this Prospectus is a part. Capitalized terms
not otherwise defined below or elsewhere in this Prospectus have the meanings
given to them in the Indenture. The definitions of certain capitalized terms
used in the summary are set forth below under "--Certain Definitions".
 
GENERAL
 
  The Exchange Notes will be unsecured senior subordinated obligations of the
Company, limited to $125 million aggregate principal amount, and will mature
on October 15, 2006. The Exchange Notes will bear interest at the rate per
annum of 10 3/8% from the date of issuance of the Exchange Notes, payable
semiannually to Holders of record at the close of business on the April 1 or
October 1 immediately preceding the interest payment date on April 15 and
October 15 of each year, commencing on the first such date following the
issuance of the Exchange Notes. Outstanding Notes that are accepted for
exchange will cease to accrue interest on and after the date on which interest
on the Exchange Notes begins to accrue. Accrued and unpaid interest on the
Outstanding Notes that are exchanged for Exchange Notes will be payable on or
before the first April 15 or October 15 following the date of issuance of the
Exchange Notes. Interest on overdue principal and (to the extent permitted by
law) on overdue installments of interest will accrue at 1% per annum in excess
of such rate. Interest on the Exchange Notes will be computed on the basis of
a 360-day year of twelve 30-day months.
 
  The Exchange Notes will be issued only in fully registered form, without
coupons, in denominations of $1,000 and any integral multiple of $1,000. No
service charge shall be made for any registration of transfer or exchange of
Exchange Notes, but the Company may require payment of a sum sufficient to
cover any transfer tax or other similar governmental charge payable in
connection therewith.
 
OPTIONAL REDEMPTION
 
  Except as set forth in the following paragraph the Exchange Notes will not
be redeemable at the option of the Company prior to October 15, 2001.
Thereafter, the Exchange Notes will be redeemable, at the Company's option, in
whole or in part, at any time or from time to time, upon not less than 30 nor
more than 60 days' prior notice mailed by first-class mail to each Holder's
registered address, at the following redemption prices (expressed in
percentages of principal amount), plus accrued interest to the redemption date
(subject to the right of Holders of record on the relevant record date to
receive interest due on the relevant interest payment date), if redeemed
during the 12-month period commencing on October 15 of the years set forth
below:
 
 
                                      72
<PAGE>
 
<TABLE>
<CAPTION>
                                                   REDEMPTION
           PERIOD                                    PRICE
           ------                                  ----------
           <S>                                     <C>
           2001...................................  105.188%
           2002...................................  102.594
           2003 and thereafter....................  100
</TABLE>
 
  In addition, at any time and from time to time prior to October 15, 1999,
the Company may redeem in the aggregate up to 35% of the original principal
amount of the Notes with the proceeds of one or more Equity Offerings
following which there is a Public Market, at a redemption price (expressed as
a percentage of principal amount) of 110.375% plus accrued interest to the
redemption date (subject to the right of Holders of record on the relevant
record date to receive interest due on the relevant interest payment date);
provided, however, that either at least $75 million aggregate principal amount
of the Notes must remain outstanding after each such redemption or such
redemption must retire the Notes in their entirety.
 
  In the case of any partial redemption, selection of the Notes for redemption
will be made by the Trustee on a pro rata basis, by lot or by such other
method as the Trustee in its sole discretion shall deem to be fair and
appropriate, although no Note of $1,000 in original principal amount or less
shall be redeemed in part. If any Note is to be redeemed in part only, the
notice of redemption relating to such Note shall state the portion of the
principal amount thereof to be redeemed. A new Note in principal amount equal
to the unredeemed portion thereof will be issued in the name of the Holder
thereof upon cancellation of the original Note.
 
SINKING FUND
 
  There will be no sinking fund payments for the Exchange Notes.
 
SUBSIDIARY GUARANTIES
 
  Kelley Operating and Kelley Oil have issued, and each other Restricted
Subsidiary of the Company (other than the Programs) that has total net assets
as of the end of the most recent fiscal year (as set forth on the balance
sheet of such Restricted Subsidiary prepared in accordance with GAAP) equal to
or greater than the greater of $2.5 million and one percent (1%) of Adjusted
Consolidated Net Tangible Assets as of such date will issue, a Subsidiary
Guaranty of the Notes as described herein. Each Subsidiary Guarantor, as
primary obligor and not merely as surety, will irrevocably and unconditionally
guarantee on a senior subordinated basis the performance and the punctual
payment when due, whether at Stated Maturity, by acceleration, by redemption
or otherwise, of all the obligations of the Company under the Indenture and
the Notes (all such obligations guaranteed by the Subsidiary Guarantors being
herein called the "Guaranteed Obligations" and each such Subsidiary Guaranty
being herein called a "Subsidiary Guaranty"). Each Subsidiary Guaranty will be
limited in amount to an amount not to exceed the maximum amount that can,
after giving effect to all other contingent and fixed liabilities of the
applicable Subsidiary Guarantor, be guaranteed by such Subsidiary Guarantor
without rendering such Subsidiary Guaranty voidable under applicable law
relating to fraudulent transfer or fraudulent conveyance or similar laws
affecting the rights of creditors generally. Each Subsidiary Guarantor will
agree to pay, in addition to the amount stated above, any and all expenses
(including reasonable counsel fees and expenses) incurred by the Trustee and
the Holders in enforcing any rights under the Subsidiary Guaranty with respect
to such Subsidiary Guarantor.
 
  Each Subsidiary Guaranty is a continuing guarantee and shall (a) remain in
full force and effect until payment in full of all the Guaranteed Obligations,
(b) be binding upon the relevant Subsidiary Guarantor and (c) enure to the
benefit of and be enforceable by the Trustee, the Holders and their
successors, transferees and assigns.
 
  Pursuant to the Indenture, any Subsidiary Guarantor may consolidate with,
merge with or into, or transfer all or substantially all its assets to any
other Person to the same extent the Company may consolidate with, merge with
or into, or transfer all or substantially all its assets to, any other Person;
provided, however, that if such Person is not the Company or a Subsidiary
Guarantor, such Subsidiary Guarantor's obligations under the
 
                                      73
<PAGE>
 
Indenture and its Subsidiary Guaranty must be expressly assumed by such other
Person. However, upon the sale or disposition (by merger or otherwise) of any
Subsidiary Guarantor to an entity (other than to the Company or a Subsidiary
Guarantor) permitted by the Indenture, such Subsidiary Guarantor will be
released and relieved from all its obligations under its Subsidiary Guaranty.
See "--Certain Covenants--Merger and Consolidation".
 
RANKING
 
  The indebtedness evidenced by the Exchange Notes and any Subsidiary Guaranty
will be unsecured, general obligations of the Company and the relevant
Subsidiary Guarantor, respectively, subordinated in right of payment, as set
forth in the Indenture, to the prior payment of all Senior Indebtedness of the
Company or Senior Indebtedness of the applicable Subsidiary Guarantor, as the
case may be, including the Company's and such Subsidiary Guarantor's
obligations under the Credit Agreement. After giving pro forma effect to the
Refinancing, as of September 30, 1996, the Company would have had
approximately $7.0 million of Senior Indebtedness outstanding.
 
  Only Indebtedness of the Company that is Senior Indebtedness will rank
senior to the Exchange Notes and only Indebtedness of a Subsidiary Guarantor
that is Senior Indebtedness of such Subsidiary Guarantor will rank senior to
such Subsidiary Guarantor's Subsidiary Guaranty, in each case in accordance
with the provisions of the Indenture. The Exchange Notes and the Subsidiary
Guaranties will in all respects rank pari passu with all other Senior
Subordinated Indebtedness of the Company or Senior Subordinated Indebtedness
of the relevant Subsidiary Guarantor, as the case may be. The Company has
agreed in the Indenture that it will not Incur, directly or indirectly, and it
will not permit any Subsidiary Guarantor to Incur, directly or indirectly, any
Indebtedness that is subordinate or junior in ranking in right of payment to
its Senior Indebtedness unless such Indebtedness is Senior Subordinated
Indebtedness or is expressly subordinated in right of payment to Senior
Subordinated Indebtedness. Unsecured Indebtedness is not deemed to be
subordinated or junior to Secured Indebtedness merely because it is unsecured.
 
  Substantially all the operations of the Company are currently conducted
through its subsidiaries. Claims of creditors of such subsidiaries, including
trade creditors, secured creditors and creditors holding guarantees issued by
such subsidiaries, and claims of preferred stockholders (if any) of such
subsidiaries generally will have priority with respect to the assets and
earnings of such subsidiaries over the claims of creditors of the Company,
including holders of the Exchange Notes, even though such obligations may not
constitute Senior Indebtedness. The Exchange Notes and each Subsidiary
Guaranty, therefore, will be effectively subordinated to creditors (including
trade creditors) and preferred stockholders (if any) of subsidiaries of the
Company (other than the relevant Subsidiary Guarantor). After giving pro forma
effect to the Refinancing, as of September 30, 1996, the Company's
subsidiaries (other than the Subsidiary Guarantors) would have had no
liabilities to any Person other than the Company and its subsidiaries.
Although the Indenture limits the incurrence of Indebtedness and the issuance
of preferred stock of certain of the Company's subsidiaries, such limitation
is subject to a number of significant qualifications; moreover, the Indenture
does not impose any limitation on the incurrence by such subsidiaries of
liabilities that are not considered Indebtedness under the Indenture. See
"--Certain Covenants--Limitation on Indebtedness and Preferred Stock of
Subsidiaries".
 
  The Company may not pay principal of, premium (if any) or interest on, the
Notes or make any deposit pursuant to the provisions described under
"Defeasance" below and may not repurchase, redeem or otherwise retire any
Notes (collectively, "pay the Notes") if (i) any Designated Senior
Indebtedness is not paid when due or (ii) any other default on Designated
Senior Indebtedness occurs and the maturity of such Designated Senior
Indebtedness is accelerated in accordance with its terms unless, in either
case, the default has been cured or waived and any such acceleration has been
rescinded or such Designated Senior Indebtedness has been paid in full.
However, the Company may pay the Notes without regard to the foregoing if the
Company and the Trustee receive written notice approving such payment from the
Representative of the Designated Senior Indebtedness with respect to which
either of the events set forth in clause (i) or (ii) of the immediately
preceding sentence has occurred and is continuing. During the continuance of
any default (other than a default described in clause (i) or (ii) of the
second preceding sentence) with respect to any Designated Senior Indebtedness
pursuant to which the
 
                                      74
<PAGE>
 
maturity thereof may be accelerated immediately without further notice (except
such notice as may be required to effect such acceleration) or the expiration
of any applicable grace periods, the Company may not pay the Notes for a
period (a "Payment Blockage Period") commencing upon the receipt by the
Trustee (with a copy to the Company) of written notice (a "Blockage Notice")
of such default from the Representative of the holders of such Designated
Senior Indebtedness specifying an election to effect a Payment Blockage Period
and ending 179 days thereafter (or earlier if such Payment Blockage Period is
terminated (i) by written notice to the Trustee and the Company from the
Person or Persons who gave such Blockage Notice, (ii) because the default
giving rise to such Blockage Notice is no longer continuing or (iii) because
such Designated Senior Indebtedness has been repaid in full). Notwithstanding
the provisions described in the immediately preceding sentence, unless the
holders of such Designated Senior Indebtedness or the Representative of such
holders have accelerated the maturity of such Designated Senior Indebtedness,
the Company must resume payments on the Notes after the end of such Payment
Blockage Period. The Notes shall not be subject to more than one Payment
Blockage Period in any consecutive 360-day period, irrespective of the number
of defaults with respect to Designated Senior Indebtedness during such period.
 
  Upon any payment or distribution of the assets of the Company upon a total
or partial liquidation or dissolution or reorganization of or similar
proceeding relating to the Company or its property, the holders of Senior
Indebtedness will be entitled to receive payment in full of such Senior
Indebtedness before the Noteholders are entitled to receive any payment, and
until the Senior Indebtedness is paid in full, any payment or distribution to
which Noteholders would be entitled but for the subordination provisions of
the Indenture will be made to holders of such Senior Indebtedness as their
interests may appear. If a distribution is made to Noteholders that, due to
the subordination provisions, should not have been made to them, such
Noteholders are required to hold it in trust for the holders of Senior
Indebtedness and pay it over to them as their interests may appear.
 
  If payment of the Notes is accelerated because of an Event of Default, the
Company or the Trustee shall promptly notify the holders of Designated Senior
Indebtedness or the Representative of such holders of the acceleration.
 
  The obligations of a Subsidiary Guarantor under its Subsidiary Guaranty, as
they relate to the principal of and interest on the Notes, are unsecured
senior subordinated obligations. As such, the rights of Noteholders to receive
payment by a Subsidiary Guarantor pursuant to its Subsidiary Guaranty will be
subordinated in right of payment to the rights of holders of Senior
Indebtedness of such Subsidiary Guarantor. The terms of the subordination
provisions described above with respect to the Company's obligations under the
Notes apply equally to a Subsidiary Guarantor and the obligations of such
Subsidiary Guarantor under its Subsidiary Guaranty, as they relate to the
principal of and interest on the Notes.
 
  By reason of the subordination provisions contained in the Indenture, in the
event of insolvency, creditors of the Company who are holders of Senior
Indebtedness may recover more, ratably, than the Noteholders, and creditors of
the Company who are not holders of Senior Indebtedness may recover less,
ratably, than holders of Senior Indebtedness and may recover more, ratably,
than the Noteholders.
 
  Notwithstanding the foregoing, payment from the money or the proceeds of
U.S. Government Obligations held in any defeasance trust described under
"Defeasance" below will not be contractually subordinated in right of payment
to any Senior Indebtedness or subject to the restrictions described herein.
 
CERTAIN DEFINITIONS
 
  "Additional Assets" means (i) any property or assets (other than
Indebtedness and Capital Stock) in the Oil and Gas Business; (ii) the Capital
Stock of a Person that becomes a Restricted Subsidiary as a result of the
acquisition of such Capital Stock by the Company or another Restricted
Subsidiary or (iii) Capital Stock constituting a minority interest in any
Person that at such time is a Restricted Subsidiary; provided, however,
 
                                      75
<PAGE>
 
that any such Restricted Subsidiary described in clauses (ii) or (iii) above
is primarily engaged in the Oil and Gas Business.
 
  "Adjusted Consolidated Assets" means at any time the total amount of assets
of the Company and its consolidated Restricted Subsidiaries (less applicable
depreciation, amortization and other valuation reserves), after deducting
therefrom all current liabilities of the Company and its consolidated
Restricted Subsidiaries (excluding intercompany items), all as set forth on
the consolidated balance sheet of the Company and its consolidated Restricted
Subsidiaries as of the end of the most recent fiscal quarter ended at least 45
days prior to the date of determination.
 
  "Adjusted Consolidated Net Tangible Assets" or "CNTA" means (without
duplication), as of the date of determination, (a) the sum of (i) discounted
future net revenues from proved oil and gas reserves of the Company and its
Restricted Subsidiaries calculated in accordance with SEC guidelines before
any state or federal income taxes, as estimated in a reserve report prepared
as of the end of the Company's most recently completed fiscal year, which
reserve report is prepared or reviewed by independent petroleum engineers, as
increased by, as of the date of determination, the discounted future net
revenues of (A) estimated proved oil and gas reserves of the Company and its
Restricted Subsidiaries attributable to any material acquisition consummated
since the date of such year-end reserve report, and (B) estimated oil and gas
reserves of the Company and its Restricted Subsidiaries attributable to
material extensions, discoveries and other additions and upward determinations
of estimates of proved oil and gas reserves due to exploration, development or
exploitation, production or other activities conducted or otherwise occurring
since the date of such year-end reserve report which would, in the case of
determinations made pursuant to clauses (A) and (B), in accordance with
standard industry practice, result in such additions or revisions, in each
case calculated in accordance with SEC guidelines (utilizing the prices
utilized in such year-end reserve report), and decreased by, as of the date of
determination, the discounted future net revenues of (C) estimated proved oil
and gas reserves of the Company and its Restricted Subsidiaries produced or
disposed of since the date of such year-end reserve report and (D) reductions
in the estimated oil and gas reserves of the Company and its Restricted
Subsidiaries since the date of such year-end reserve report attributable to
material downward determinations of estimates of proved oil and gas reserves
due to exploration, development or exploitation, production or other
activities conducted or otherwise occurring since the date of such year-end
reserve report which would, in the case of determinations made pursuant to
clauses (C) and (D), in accordance with standard industry practice, result in
such determinations, in each case calculated in accordance with SEC guidelines
(utilizing the prices utilized in such year-end reserve report); provided
that, in the case of each of the determinations made pursuant to clauses (A)
through (D), such increases and decreases shall be as estimated by the
Company's engineers, except that if as a result of such acquisitions,
dispositions, discoveries, extensions or revisions, there is a Material Change
which is an increase, then such increases and decreases in the discounted
future net revenue shall be confirmed in writing by an independent petroleum
engineer, (ii) the capitalized costs that are attributable to oil and gas
properties of the Company and its Restricted Subsidiaries to which no proved
oil and gas reserves are attributed, based on the Company's books and records
as of a date no earlier than the date of the Company's latest annual or
quarterly financial statements, (iii) the Net Working Capital on a date no
earlier than the date of the Company's latest annual or quarterly financial
statements and (iv) the greater of (I) the net book value on a date no earlier
than the date of the Company's latest annual or quarterly financial statements
and (II) the appraised value, as estimated by independent appraisers, of other
tangible assets of the Company and its Restricted Subsidiaries as of a date no
earlier than the date of the Company's latest audited financial statements
(provided that the Company shall not be required to obtain such an appraisal
of such assets if no such appraisal has been performed), minus (b) the sum of
(i) minority interests, (ii) any gas balancing liabilities of the Company and
its Restricted Subsidiaries reflected in the Company's latest audited
financial statements, (iii) the discounted future net revenue, calculated in
accordance with SEC guidelines (utilizing the same prices utilized in the
Company's year-end reserve report), attributable to reserves subject to
participation interests, overriding royalty interests or other interests of
third parties, pursuant to participation, partnership, vendor financing or
other agreements then in effect, or which otherwise are required to be
delivered to third parties, (iv) the discounted future net revenues,
calculated in accordance with SEC guidelines (utilizing the same prices
utilized in the Company's year-end reserve report), attributable to reserves
that are required to
 
                                      76
<PAGE>
 
be delivered to third parties to fully satisfy the obligations of the Company
and its Restricted Subsidiaries with respect to Volumetric Production Payments
on the schedules specified with respect thereto and (v) the discounted future
net revenues, calculated in accordance with SEC guidelines, attributable to
reserves subject to Dollar-Denominated Production Payments that, based on the
estimates of production included in determining the discounted future net
revenues specified in the immediately preceding clause (a)(i) (utilizing the
same prices utilized in the Company's year-end reserve report), would be
necessary to satisfy fully the obligations of the Company and its Restricted
Subsidiaries with respect to Dollar-Denominated Production Payments on the
schedules specified with respect thereto.
 
  "Affiliate" of any specified Person means any other Person, directly or
indirectly, controlling or controlled by or under direct or indirect common
control with such specified Person. For the purposes of this definition,
"control" when used with respect to any Person means the power to direct the
management and policies of such Person, directly or indirectly, whether
through the ownership of voting securities, by contract or otherwise; and the
terms "controlling" and "controlled" have meanings correlative to the
foregoing. For purposes of the provisions described under "--Certain
Covenants--Limitation on Restricted Payments", "--Certain Covenants--
Limitation on Affiliate Transactions" and "--Certain Covenants--Limitations on
Sales of Assets and Subsidiary Stock" only, "Affiliate" shall also mean any
beneficial owner of Capital Stock representing 5% or more of the total voting
power of the Voting Stock (on a fully diluted basis) of the Company or of
rights or warrants to purchase such Capital Stock (whether or not currently
exercisable) and any Person who would be an Affiliate of any such beneficial
owner pursuant to the first sentence hereof. Shareholders and Affiliates of
Bessemer Securities Corporation ("BSC") that would not be Affiliates of the
Company other than by reason of being shareholders or Affiliates of BSC and
that neither in fact participate in the management of any of BSC, Bessemer,
Holdings or the Company, nor are controlled by BSC, Bessemer, Holdings, the
Company, or any of their respective Affiliates who in fact participate in the
management of any of BSC, Bessemer, Holdings or the Company, shall not be
deemed to be "Affiliates" of the Company.
 
  "Asset Disposition" means any sale, lease, transfer or other disposition (or
series of related sales, leases, transfers or dispositions) by the Company or
any Restricted Subsidiary, including any disposition by means of a merger,
consolidation or similar transaction (each referred to for the purposes of
this definition as a "disposition"), of (i) any shares of Capital Stock of a
Restricted Subsidiary (other than directors' qualifying shares or shares
required by applicable law to be held by a Person other than the Company or a
Restricted Subsidiary), (ii) all or substantially all the assets of any
division or line of business of the Company or any Restricted Subsidiary or
(iii) any other assets of the Company or any Restricted Subsidiary outside of
the ordinary course of business of the Company or such Restricted Subsidiary.
Notwithstanding the foregoing, none of the following shall be deemed to be an
Asset Disposition: (1) a disposition by a Restricted Subsidiary to the Company
or by the Company or a Restricted Subsidiary to a Wholly Owned Subsidiary, (2)
for purposes of the covenant described under "--Certain Covenants--Limitation
on Sales of Assets and Subsidiary Stock" only, a disposition that constitutes
a Restricted Payment permitted by the covenant described under "--Certain
Covenants--Limitation on Restricted Payments"), (3) the sale or transfer
(whether or not in the ordinary course of business) of oil and gas properties
or direct or indirect interests in real property; provided, however, that at
the time of such sale or transfer such properties do not have associated with
them any proved reserves, (4) the abandonment, farm-out, lease or sublease of
developed or undeveloped oil and gas properties in the ordinary course of
business, (5) the trade or exchange by the Company or any Restricted
Subsidiary of any oil and gas property owned or held by the Company or such
Restricted Subsidiary for any oil and gas property owned or held by another
Person or (6) the sale or transfer of hydrocarbons or other mineral products
or surplus or obsolete equipment in the ordinary course of business.
 
  "Attributable Debt" in respect of a Sale/Leaseback Transaction means, as at
the time of determination, the present value (discounted at the interest rate
implicit in the Sale/Leaseback Transaction, compounded annually) of the total
obligations of the lessee for rental payments during the remaining term of the
lease included in such Sale/Leaseback Transaction (including any period for
which such lease has been extended).
 
 
                                      77
<PAGE>
 
  "Average Life" means, as of the date of determination, with respect to any
Indebtedness or Preferred Stock, the quotient obtained by dividing (i) the sum
of the products of numbers of years from the date of determination to the
dates of each successive scheduled principal payment of such Indebtedness or
redemption or similar payment with respect to such Preferred Stock multiplied
by the amount of such payment by (ii) the sum of all such payments.
 
  "Banks" has the meaning specified in the Credit Agreement.
 
  "Board of Directors" means the Board of Directors of the Company or any
committee thereof duly authorized to act on behalf of such Board.
 
  "Business Day" means each day which is not a Legal Holiday (as defined in
the Indenture).
 
  "Capital Lease Obligations" means an obligation that is required to be
classified and accounted for as a capital lease for financial reporting
purposes in accordance with GAAP, and the amount of Indebtedness represented
by such obligation shall be the capitalized amount of such obligation
determined in accordance with GAAP; and the Stated Maturity thereof shall be
the date of the last payment of rent or any other amount due under such lease
prior to the first date upon which such lease may be terminated by the lessee
without payment of a penalty.
 
  "Capital Stock" of any Person means any and all shares, interests, rights to
purchase, warrants, options, participations or other equivalents of or
interests in (however designated) equity of such Person, including any
Preferred Stock, but excluding any debt securities convertible into such
equity.
 
  "Change of Control" means the occurrence of any of the following events:
 
    (i) any "person" (as such term is used in Sections 13(d) and 14(d) of the
  Exchange Act), other than one or more Permitted Holders, is or becomes the
  beneficial owner (as defined in Rules 13d-3 and 13d-5 under the Exchange
  Act, except that for purposes of this clause (i) such person shall be
  deemed to have "beneficial ownership" of all shares that such person has
  the right to acquire, whether such right is exercisable immediately or only
  after the passage of time), directly or indirectly, of more than 35% of the
  total voting power of the Voting Stock of the Company; provided, however,
  that the Permitted Holders beneficially own (as defined in Rules 13d-3 and
  13d-5 under the Exchange Act), directly or indirectly, in the aggregate a
  lesser percentage of the total voting power of the Voting Stock of the
  Company than such other person and do not have the right or ability by
  voting power, contract or otherwise to elect or designate for election a
  majority of the Board of Directors (for the purposes of this clause (i),
  such other person shall be deemed to beneficially own any Voting Stock of a
  specified corporation held by a parent corporation, if such other person is
  the beneficial owner (as defined in this clause (i)), directly or
  indirectly, of more than 35% of the voting power of the Voting Stock of
  such parent corporation and the Permitted Holders beneficially own (as
  defined in this proviso), directly or indirectly, in the aggregate a lesser
  percentage of the voting power of the Voting Stock of such parent
  corporation and do not have the right or ability by voting power, contract
  or otherwise to elect or designate for election a majority of the board of
  directors of such parent corporation);
 
    (ii) during any period of two consecutive years from and after the Issue
  Date, individuals who at the beginning of such period constituted the Board
  of Directors (together with any new directors whose election by such Board
  of Directors or whose nomination for election by the shareholders of the
  Company was approved by a vote of a majority of the directors of the
  Company then still in office who were either directors at the beginning of
  such period or whose election or nomination for election was previously so
  approved) cease for any reason to constitute a majority of the Board of
  Directors then in office; or
 
    (iii) the merger or consolidation of the Company with or into another
  Person or the merger of another Person with or into the Company, or the
  sale of all or substantially all the assets of the Company to another
  Person (other than a Person that is controlled by the Permitted Holders),
  and, in the case of any such merger
 
                                      78
<PAGE>
 
  or consolidation, the securities of the Company that are outstanding
  immediately prior to such transaction and which represent 100% of the
  aggregate voting power of the Voting Stock of the Company are changed into
  or exchanged for cash, securities or property, unless pursuant to such
  transaction such securities are changed into or exchanged for, in addition
  to any other consideration, securities of the surviving corporation that
  represent immediately after such transaction, at least a majority of the
  aggregate voting power of the Voting Stock of the surviving corporation.
 
  "Code" means the Internal Revenue Code of 1986, as amended.
 
  "Consolidated Coverage Ratio" as of any date of determination means the
ratio of (i) the aggregate amount of EBITDA for the period of the most recent
four consecutive fiscal quarters ending at least 45 days prior to the date of
such determination to (ii) Consolidated Interest Expense for such four fiscal
quarters; provided, however, that (1) if the Company or any Restricted
Subsidiary has Incurred any Indebtedness since the beginning of such period
that remains outstanding or if the transaction giving rise to the need to
calculate the Consolidated Coverage Ratio is an Incurrence of Indebtedness, or
both, EBITDA and Consolidated Interest Expense for such period shall be
calculated after giving effect on a pro forma basis to such Indebtedness as if
such Indebtedness had been Incurred on the first day of such period and the
discharge of any other Indebtedness repaid, repurchased, defeased or otherwise
discharged with the proceeds of such new Indebtedness as if such discharge had
occurred on the first day of such period, (2) if the Company or any Restricted
Subsidiary has repaid, repurchased, defeased or otherwise discharged any
Indebtedness since the beginning of such period or if any Indebtedness is to
be repaid, repurchased, defeased or otherwise discharged on the date of the
transaction giving rise to the need to calculate the Consolidated Coverage
Ratio, EBITDA and Consolidated Interest Expense for such period shall be
calculated on a pro forma basis as if such discharge had occurred on the first
day of such period and as if the Company or such Restricted Subsidiary has not
earned the interest income actually earned during such period in respect of
cash or Temporary Cash Investments used to repay, repurchase, defease or
otherwise discharge such Indebtedness, (3) if since the beginning of such
period the Company or any Restricted Subsidiary shall have made any Asset
Disposition (other than an Asset Disposition involving assets having a fair
market value of less than the greater of one percent (1%) of Adjusted
Consolidated Net Tangible Assets as of the end of the Company's then most
recently completed fiscal year and $2.0 million), then EBITDA for such period
shall be reduced by an amount equal to EBITDA (if positive) directly
attributable to the assets which are the subject of such Asset Disposition for
such period, or increased by an amount equal to EBITDA (if negative), directly
attributable thereto for such period and Consolidated Interest Expense for
such period shall be reduced by an amount equal to the Consolidated Interest
Expense directly attributable to any Indebtedness of the Company or any
Restricted Subsidiary repaid, repurchased, defeased or otherwise discharged
with respect to the Company and its continuing Restricted Subsidiaries in
connection with such Asset Disposition for such period (or, if the Capital
Stock of any Restricted Subsidiary is sold, the Consolidated Interest Expense
for such period directly attributable to the Indebtedness of such Restricted
Subsidiary to the extent the Company and its continuing Restricted
Subsidiaries are no longer liable for such Indebtedness after such sale), (4)
if since the beginning of such period the Company or any Restricted Subsidiary
(by merger or otherwise) shall have made an Investment in any Restricted
Subsidiary (or any person which becomes a Restricted Subsidiary) or an
acquisition (including by way of lease) of assets, including any acquisition
of assets occurring in connection with a transaction requiring a calculation
to be made hereunder, EBITDA and Consolidated Interest Expense for such period
shall be calculated after giving pro forma effect thereto (including the
Incurrence of any Indebtedness) as if such Investment or acquisition occurred
on the first day of such period and (5) if since the beginning of such period
any Person (that subsequently became a Restricted Subsidiary or was merged
with or into the Company or any Restricted Subsidiary since the beginning of
such period) shall have made any Asset Disposition, any Investment or
acquisition of assets that would have required an adjustment pursuant to
clause (3) or (4) above if made by the Company or a Restricted Subsidiary
during such period, EBITDA and Consolidated Interest Expense for such period
shall be calculated after giving pro forma effect thereto as if such Asset
Disposition, Investment or acquisition occurred on the first day of such
period. For purposes of this definition, whenever pro forma effect is to be
given to an acquisition of assets, the amount of income or earnings relating
thereto and the amount of Consolidated Interest Expense associated with any
Indebtedness Incurred in connection therewith, the pro forma
 
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<PAGE>
 
calculations shall be determined in good faith by a responsible financial or
accounting Officer of the Company. If any Indebtedness bears a floating rate
of interest and is being given pro forma effect, the interest of such
Indebtedness shall be calculated as if the rate in effect on the date of
determination had been the applicable rate for the entire period (taking into
account any Interest Rate Agreement applicable to such Indebtedness if such
Interest Rate Agreement has a remaining term in excess of 12 months).
 
  "Consolidated Current Liabilities" as of the date of determination means the
aggregate amount of liabilities of the Company and its consolidated Restricted
Subsidiaries which may properly be classified as current liabilities
(including taxes accrued as estimated), on a consolidated basis, after
eliminating (i) all intercompany items between the Company and any Restricted
Subsidiary and (ii) all current maturities of long-term Indebtedness, all as
determined in accordance with GAAP consistently applied.
 
  "Consolidated Interest Expense" means, for any period, the total interest
expense of the Company and its consolidated Restricted Subsidiaries for such
period, determined on a consolidated basis in accordance with GAAP, plus, to
the extent not included in such total interest expense, and to the extent
incurred by the Company or its Restricted Subsidiaries, without duplication,
(i) interest expense attributable to capital leases and imputed interest with
respect to Attributable Debt, (ii) capitalized interest, (iii) non-cash
interest expenses, (iv) commissions, discounts and other fees and charges owed
with respect to letters of credit and bankers' acceptance financing, (v) net
costs (including amortization of fees and upfront payments) associated with
interest rate caps and other interest rate and currency options that, at the
time entered into, resulted in the Company and its Restricted Subsidiaries
being net payees as to future payouts under such caps or options, and interest
rate and currency swaps and forwards for which the Company or any of its
Restricted Subsidiaries has paid a premium, (vi) Preferred Stock dividends in
respect of all Preferred Stock held by Persons other than the Company or a
Wholly Owned Subsidiary, to the extent that, by the terms of the Preferred
Stock, failure to pay such dividends would result in a bankruptcy of the
issuer thereof and (vii) interest accruing on any Indebtedness of any other
Person to the extent such Indebtedness is Guaranteed by the Company or any
Restricted Subsidiary or secured by a Lien on assets of the Company or any
Restricted Subsidiary to the extent such Indebtedness constitutes Indebtedness
of the Company or any Restricted Subsidiary (whether or not such Guarantee or
Lien is called upon); provided, however, "Consolidated Interest Expense" shall
not include any (w) amortization of costs relating to debt issuances
(including the amortization of debt discount) other than the amortization of
debt discount related to the issuance of securities with an original issue
price of not more than 90% of the principal thereof, (x) amortization of debt
discount to the extent it relates to revaluations of financial instruments
recognized in connection with the Consolidation, (y) Consolidated Interest
Expense with respect to any Indebtedness Incurred pursuant to clause (b)(8) of
the covenant described under "--Certain Covenants--Limitation on Indebtedness"
and (z) noncash interest expense Incurred in connection with interest rate
caps and other interest rate and currency options that, at the time entered
into, resulted in the Company and its Restricted Subsidiaries being either
neutral or net payors as to future payouts under such caps or options.
 
  "Consolidated Net Income" means, for any period, the net income of the
Company and its consolidated Subsidiaries; provided, however, that there shall
not be included in such Consolidated Net Income: (i) any net income of any
Person (other than the Company) if such Person is not a Restricted Subsidiary,
except that (A) subject to the exclusion contained in clause (iv) below, the
Company's equity in the net income of any such Person for such period shall be
included in such Consolidated Net Income up to the aggregate amount of cash
actually distributed by such Person during such period to the Company or a
Restricted Subsidiary as a dividend or other distribution (subject, in the
case of a dividend or other distribution paid to a Restricted Subsidiary, to
the limitations contained in clause (iii) below) and (B) the Company's equity
in a net loss of any such Person for such period shall be included in
determining such Consolidated Net Income; (ii) any net income (or loss) of any
Person acquired by the Company or a Subsidiary in a pooling of interests
transaction for any period prior to the date of such acquisition; (iii) any
net income of any Restricted Subsidiary if such Restricted Subsidiary is
subject to restrictions, directly or indirectly, on the payment of dividends
or the making of distributions by such Restricted Subsidiary, directly or
indirectly, to the Company, except that (A) subject to the exclusion contained
in clause (iv) below, the Company's equity in the net income of any such
Restricted Subsidiary for such period
 
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<PAGE>
 
shall be included in such Consolidated Net Income up to the aggregate amount
of cash actually distributed by such Restricted Subsidiary during such period
to the Company or another Restricted Subsidiary as a dividend or other
distribution (subject, in the case of a dividend or other distribution paid to
another Restricted Subsidiary, to the limitation contained in this clause) and
(B) the Company's equity in a net loss of any such Restricted Subsidiary for
such period shall be included in determining such Consolidated Net Income;
(iv) any gain or loss realized upon the sale or other disposition of any
assets of the Company or its consolidated Subsidiaries (including pursuant to
any sale-and-leaseback arrangement) which is not sold or otherwise disposed of
in the ordinary course of business and any gain or loss realized upon the sale
or other disposition of any Capital Stock of any Person; (v) extraordinary
gains or losses; and (vi) the cumulative effect of a change in accounting
principles. Notwithstanding the foregoing, for the purposes of the covenant
described under "Certain Covenants--Limitation on Restricted Payments" only,
there shall be excluded from Consolidated Net Income any dividends, repayments
of loans or advances or other transfers of assets from Unrestricted
Subsidiaries to the Company or a Restricted Subsidiary to the extent such
dividends, repayments or transfers increase the amount of Restricted Payments
permitted under such covenant pursuant to clause (a)(3)(E) thereof.
 
  "Consolidated Net Tangible Assets", as of any date of determination, means
the total amount of assets (less accumulated depreciation and amortization,
allowances for doubtful receivables, other applicable reserves and other
properly deductible items) which would appear on a consolidated balance sheet
of the Company and its consolidated Restricted Subsidiaries, determined on a
consolidated basis in accordance with GAAP, and after giving effect to
purchase accounting and after deducting therefrom Consolidated Current
Liabilities and, to the extent otherwise included, the amounts of: (i)
minority interests in consolidated Subsidiaries held by Persons other than the
Company or a Restricted Subsidiary; (ii) excess of cost over fair value of
assets of businesses acquired, as determined in good faith by the Board of
Directors; (iii) any revaluation or other write-up in book value of assets
subsequent to the Issue Date as a result of a change in the method of
valuation in accordance with GAAP consistently applied; (iv) unamortized debt
discount and expenses and other unamortized deferred charges, goodwill,
patents, trademarks, service marks, trade names, copyrights, licenses,
organization or developmental expenses and other intangible items; (v)
treasury stock; (vi) cash set apart and held in a sinking or other analogous
fund established for the purpose of redemption or other retirement of Capital
Stock to the extent such obligation is not reflected in Consolidated Current
Liabilities; and (vii) Investments in and assets of Unrestricted Subsidiaries.
 
  "Consolidated Net Worth" means the total of the amounts shown on the balance
sheet of the Company and its consolidated Subsidiaries, determined on a
consolidated basis in accordance with GAAP, as of the end of the most recent
fiscal quarter of the Company ending at least 45 days prior to the taking of
any action for the purpose of which the determination is being made, as (i)
the par or stated value of all outstanding Capital Stock of the Company plus
(ii) paid-in capital or capital surplus relating to such Capital Stock plus
(iii) any retained earnings or earned surplus less (A) any accumulated deficit
and (B) any amounts attributable to Disqualified Stock.
 
  "Contour Option" means that certain Option Agreement, dated as of February
15, 1996, between the Company and Contour Production Company L.L.C., a
Delaware limited liability company.
 
  "Credit Agreement" means that certain Credit Agreement, dated as of February
14, 1996, by and among the Company and Texas Commerce Bank National
Association (or any successor thereto or replacement thereof), as agent and as
a lender, and certain other institutions, as lenders, including any related
notes, guarantees, collateral documents, instruments and agreements executed
in connection therewith, and in each case as amended, restated, modified,
renewed, refunded, replaced or refinanced, in whole or in part, from time to
time.
 
  "Credit Facilities" means, with respect to the Company or any Restricted
Subsidiary, one or more debt facilities (including the Credit Agreement) or
commercial paper facilities with banks or other institutional lenders
providing for revolving credit loans, term loans, production payments,
receivables financing (including through the sale of receivables to such
lenders or to special purpose entities formed to borrow from such lenders
against
 
                                      81
<PAGE>
 
such receivables) or letters of credit, in each case, as amended, restated,
modified, renewed, refunded, replaced or refinanced in whole or in part from
time to time.
 
  "Currency Agreement" means in respect of a Person any foreign exchange
contract, currency swap agreement or other similar agreement to which such
Person is a party or a beneficiary.
 
  "Default" means any event which is, or after notice or passage of time or
both would be, an Event of Default.
 
  "Designated Senior Indebtedness" means (i) all the obligations of the
Company or any Restricted Subsidiary under any Credit Facility and (ii) any
other Senior Indebtedness of the Company which, at the date of determination,
has an aggregate principal amount outstanding of, or under which, at the date
of determination, the holders thereof are committed to lend up to, at least
$25.0 million and is specifically designated by the Company in the instrument
evidencing or governing such Senior Indebtedness as "Designated Senior
Indebtedness" for purposes of the Indenture.
 
  "Disqualified Stock" means, with respect to any Person, any Capital Stock to
the extent that by its terms (or by the terms of any security into which it is
convertible or for which it is exchangeable) or upon the happening of any
event, it (i) matures or is mandatorily redeemable pursuant to a sinking fund
obligation or otherwise, (ii) is convertible or exchangeable for Indebtedness
or Disqualified Stock or (iii) is redeemable, in whole or in part, at the
option of the holder thereof, in each case described in the immediately
preceding clauses (i), (ii) or (iii), on or prior to the Stated Maturity of
the Notes; provided, however, that any Capital Stock that would not constitute
Disqualified Stock but for provisions thereof giving holders thereof the right
to require such Person to repurchase or redeem such Capital Stock upon the
occurrence of an "asset sale" or "change of control" occurring prior to the
Stated Maturity of the Notes shall not constitute Disqualified Stock if the
"asset sale" or "change of control" provisions applicable to such Capital
Stock are not more favorable to the holders of such Capital Stock than the
provisions described under "--Certain Covenants--Limitation on Sales of Assets
and Subsidiary Stock" and "--Certain Covenants--Change of Control"; provided
further, however, that the Company's Convertible Exchangeable Preferred Stock
outstanding on the Issue Date shall not be deemed Disqualified Stock.
 
  "Dollar-Denominated Production Payments" means production payment
obligations recorded as liabilities in accordance with GAAP, together with all
undertakings and obligations in connection therewith.
 
  "EBITDA" for any period means the sum of Consolidated Net Income, plus
Consolidated Interest Expense plus the following to the extent deducted in
calculating such Consolidated Net Income: (a) provision for taxes based on
income or profits, (b) depletion and depreciation expense, (c) amortization
expense (d) exploration costs and (e) all other non-cash charges (excluding
any such non-cash charge to the extent that it represents an accrual of or
reserve for cash charges in any future period or amortization of a prepaid
cash expense that was paid in a prior period except such amounts as the
Company determines in good faith are nonrecurring), and less, to the extent
included in calculating such Consolidated Net Income and in excess of any
costs or expenses attributable thereto and deducted in calculating such
Consolidated Net Income, the sum of (x) the amount of deferred revenues that
are amortized during such period and are attributable to reserves that are
subject to Volumetric Production Payments and (y) amounts recorded in
accordance with GAAP as repayments of principal and interest pursuant to
Dollar-Denominated Production Payments. Notwithstanding the foregoing, the
provision for taxes based on the income or profits of, and the depreciation
and amortization and other non-cash charges of, a Subsidiary of the Company
shall be added to Consolidated Net Income to compute EBITDA only to the extent
(and in the same proportion) that the net income of such Subsidiary was
included in calculating Consolidated Net Income and only if a corresponding
amount would be permitted at the date of determination to be dividended to the
Company by such Subsidiary without prior approval (that has not been
obtained), pursuant to the terms of its charter and all agreements,
instruments, judgments, decrees, orders, statutes, rules and governmental
regulations applicable to such Subsidiary or its stockholders.
 
 
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<PAGE>
 
  "Equity Offering" means a primary offering, whether public or private, of
shares of common stock of the Company.
 
  "Exchange Act" means the Securities Exchange Act of 1934, as amended.
 
  "GAAP" means generally accepted accounting principles in the United States
of America as in effect on the Issue Date, including those set forth in (i)
the opinions and pronouncements of the Accounting Principles Board of the
American Institute of Certified Public Accountants, (ii) statements and
pronouncements of the Financial Accounting Standards Board, (iii) such other
statements by such other entity as approved by a significant segment of the
accounting profession, and (iv) the rules and regulations of the SEC governing
the inclusion of financial statements (including pro forma financial
statements) in periodic reports required to be filed pursuant to Section 13 of
the Exchange Act, including opinions and pronouncements in staff accounting
bulletins and similar written statements from the accounting staff of the SEC.
 
  "Guarantee" means, without duplication, any obligation, contingent or
otherwise, of any Person directly or indirectly guaranteeing any Indebtedness
of any Person and any obligation, direct or indirect, contingent or otherwise,
of such Person (i) to purchase or pay (or advance or supply funds for the
purchase or payment of) such Indebtedness of such Person (whether arising by
virtue of partnership arrangements, or by agreements to keep-well, to purchase
assets, goods, securities or services, to take-or-pay or to maintain financial
statement conditions or otherwise) or (ii) entered into for the purpose of
assuring in any other manner the obligee of such Indebtedness of the payment
thereof or to protect such obligee against loss in respect thereof (in whole
or in part); provided, however, that the term "Guarantee" shall not include
endorsements for collection or deposit in the ordinary course of business. The
term "Guarantee" used as a verb has a corresponding meaning. The term
"Guarantor" shall mean any Person Guaranteeing any obligation.
 
  "Hedging Obligations" of any Person means the obligations of such Person
pursuant to any Oil and Gas Hedging Contract, Interest Rate Agreement or
Currency Agreement.
 
  "Holder" or "Noteholder" means the Person in whose name a Note is registered
on the Registrar's books.
 
  "Incur" means issue, assume, Guarantee, incur or otherwise become liable
for; provided, however, that any Indebtedness or Capital Stock of a Person
existing at the time such Person becomes a Subsidiary (whether by merger,
consolidation, acquisition or otherwise) shall be deemed to be Incurred by
such Subsidiary at the time it becomes a Subsidiary. The term "Incurrence"
when used as a noun shall have a correlative meaning. The accretion of
principal of a non-interest bearing or other discount security shall not be
deemed the Incurrence of Indebtedness.
 
  "Indebtedness" means, with respect to any Person on any date of
determination (without duplication), (i) the principal of and premium (if any)
in respect of (A) indebtedness of such Person for money borrowed and (B)
indebtedness evidenced by notes, debentures, bonds or other similar
instruments for the payment of which such Person is responsible or liable;
(ii) all Capital Lease Obligations of such Person and all Attributable Debt in
respect of Sale/Leaseback Transactions entered into by such Person; (iii) all
obligations of such Person issued or assumed as the deferred purchase price of
property (which purchase price is due more than six months after the date of
taking delivery of title to such property), including all obligations of such
Person for the deferred purchase price of property under any title retention
agreement (but excluding trade accounts payable arising in the ordinary course
of business); (iv) all obligations of such Person for the reimbursement of any
obligor on any letter of credit, banker's acceptance or similar credit
transaction (other than obligations with respect to letters of credit securing
obligations (other than obligations described in (i) through (iii) above)
entered into in the ordinary course of business of such Person to the extent
such letters of credit are not drawn upon or, if and to the extent drawn upon,
such drawing is reimbursed no later than the tenth Business Day following
receipt by such Person of a demand for reimbursement following payment on the
letter of credit); (v) the amount of all obligations of such Person with
respect to the redemption, repayment or other repurchase of any Disqualified
Stock or, with respect to any Subsidiary of such Person the liquidation
preference with respect to, any Preferred Stock (but
 
                                      83
<PAGE>
 
excluding, in each case, any accrued dividends); (vi) all obligations of such
Person relating to any Production Payment or in respect of production
imbalances (but excluding production imbalances arising in the ordinary course
of business); (vii) all obligations of the type referred to in clauses (i)
through (vi) of other Persons and all dividends of other Persons for the
payment of which, in either case, such Person is responsible or liable,
directly or indirectly, as obligor, guarantor or otherwise, including by means
of any Guarantee (including, with respect to any Production Payment, any
warranties or guarantees of production or payment by such Person with respect
to such Production Payment but excluding other contractual obligations of such
Person with respect to such Production Payment); (viii) all obligations of the
type referred to in clauses (i) through (vii) of other Persons secured by any
Lien on any property or asset of such first-mentioned Person (whether or not
such obligation is assumed by such first-mentioned Person), the amount of such
obligation being deemed to be the lesser of the value of such property or
assets or the amount of the obligation so secured and (ix) to the extent not
otherwise included in this definition, Hedging Obligations of such Person. The
amount of Indebtedness of any Person at any date shall be the outstanding
balance at such date of all unconditional obligations as described above and
the maximum liability, upon the occurrence of the contingency giving rise to
the obligation, of any contingent obligations at such date.
 
  It is understood that none of the following shall constitute Indebtedness:
(i) indebtedness arising from agreements providing for indemnification or
adjustment of purchase price or from guarantees securing any obligations of
the Company or any of its Subsidiaries pursuant to such agreements, incurred
or assumed in connection with the disposition of any business, assets or
Subsidiary of the Company, other than guarantees or similar credit support by
the Company or any of its Subsidiaries of Indebtedness incurred by any Person
acquiring all or any portion of such business, assets or Subsidiary for the
purpose of financing such acquisition; (ii) any trade payables and other
accrued current liabilities incurred in the ordinary course of business as the
deferred purchase price of property; (iii) obligations arising from guarantees
to suppliers, lessors, licensees, contractors, franchisees or customers
incurred in the ordinary course of business; (iv) obligations (other than
express Guarantees of indebtedness for borrowed money) in respect of
Indebtedness of other Persons arising in connection with (A) the sale or
discount of accounts receivable, (B) trade acceptances and (C) endorsements of
instruments for deposit in the ordinary course of business, (v) obligations in
respect of performance bonds provided by the Company or its Subsidiaries in
the ordinary course of business and refinancings thereof; (vi) obligations
arising from the honoring by a bank or other financial institution of a check,
draft or similar instrument drawn against insufficient funds in the ordinary
course of business, provided, however, that such obligation is extinguished
within two business days of its incurrence; and (vii) obligations in respect
of any obligations under workers' compensation laws and similar legislation.
 
  "Interest Rate Agreement" means any interest rate swap agreement, interest
rate cap agreement or other financial agreement or arrangement designed to
protect the Company or any Restricted Subsidiary against fluctuations in
interest rates.
 
  "Investment" in any Person means any direct or indirect advance, loan (other
than advances to customers or joint interest partners or drilling partnerships
sponsored by the Company or any Restricted Subsidiary in the ordinary course
of business that are recorded as accounts receivable on the balance sheet of
the lender) or other extensions of credit (including by way of Guarantee or
similar arrangement) or capital contribution to (by means of any transfer of
cash or other property to others or any payment for property or services for
the account or use of others), or any purchase or acquisition of Capital
Stock, Indebtedness or other similar instruments issued by such Person. For
purposes of the definition of "Unrestricted Subsidiary", the definition of
"Restricted Payment" and the covenant described under "--Certain Covenants--
Limitation on Restricted Payments", (i) "Investment" shall include the portion
(proportionate to the Company's equity interest in such Subsidiary) of the
fair market value of the net assets of any Subsidiary of the Company at the
time that such Subsidiary is designated an Unrestricted Subsidiary; provided,
however, that upon a redesignation of such Subsidiary as a Restricted
Subsidiary, the Company shall be deemed to continue to have a permanent
"Investment" in an Unrestricted Subsidiary equal to an amount (if positive)
equal to (x) the Company's "Investment" in such Subsidiary at the time of such
redesignation less (y) the portion (proportionate to the Company's equity
interest
 
                                      84
<PAGE>
 
in such Subsidiary) of the fair market value of the net assets of such
Subsidiary at the time of such redesignation; and (ii) any property
transferred to or from an Unrestricted Subsidiary shall be valued at its fair
market value at the time of such transfer, in each case as determined in good
faith by the Board of Directors.
 
  "Issue Date" means the date on which the Notes are originally issued.
 
  "Lien" means any mortgage, pledge, security interest, encumbrance, lien or
charge of any kind (including any conditional sale or other title retention
agreement or lease in the nature thereof).
 
  "Limited Recourse Indebtedness" means, with respect to any Production
Payments, Indebtedness, the terms of which limit the liability of the Company
and its Restricted Subsidiaries solely to the hydrocarbons covered by such
Production Payments; provided, however, that no default with respect to such
Indebtedness would permit any holder of any other Indebtedness of the Company
or any Restricted Subsidiary to declare a default on such other Indebtedness
or cause the payment thereof to be accelerated or payable prior to its stated
maturity.
 
  "Material Change" means an increase or decrease (excluding changes that
result solely from changes in prices) of more than 15% during a fiscal quarter
in the discounted future net revenues from proved oil and gas reserves of the
Company and its Restricted Subsidiaries, calculated in accordance with clause
(a)(i) of the definition of Adjusted Consolidated Net Tangible Assets;
provided, however, that the following will be excluded from the calculation of
Material Change: (i) any acquisitions during the fiscal quarter of oil and gas
reserves that have been estimated by independent petroleum engineers and with
respect to which a report or reports of such engineers exist and (ii) any
disposition of properties existing at the beginning of such fiscal quarter
that have been disposed of in compliance with the covenant described under
"--Certain Covenants--Limitation on Sales of Assets and Subsidiary Stock".
 
  "Net Available Cash" from an Asset Disposition means cash payments received
therefrom (including any cash payments received by way of deferred payment of
principal pursuant to a note or installment receivable or otherwise, but only
as and when received, but excluding any other consideration received in the
form of assumption by the acquiring Person of Indebtedness or other
obligations relating to such properties or assets or received in any other
noncash form) in each case net of (i) all legal, title and recording tax
expenses, commissions and other fees (including financial and other advisory
fees) and expenses incurred, and all Federal, state, provincial, foreign and
local taxes required to be accrued as a liability under GAAP, as a consequence
of such Asset Disposition, (ii) all payments made on any Indebtedness which is
secured by any assets subject to such Asset Disposition, in accordance with
the terms of any Lien upon or other security agreement of any kind with
respect to such assets, or which must by its terms, or in order to obtain a
necessary consent to such Asset Disposition, or by applicable law, be repaid
out of the proceeds from such Asset Disposition, (iii) all distributions and
other payments required to be made to minority interest holders in
Subsidiaries or joint ventures as a result of such Asset Disposition and (iv)
the deduction of appropriate amounts provided by the seller as a reserve, in
accordance with GAAP, against any liabilities associated with the property or
other assets disposed in such Asset Disposition and retained by the Company or
any Restricted Subsidiary after such Asset Disposition.
 
  "Net Cash Proceeds", with respect to any issuance or sale of Capital Stock,
means the cash proceeds of such issuance or sale net of attorneys' fees,
accountants' fees, underwriters' or placement agents' fees, discounts or
commissions and brokerage, consultant and other fees actually incurred in
connection with such issuance or sale and net of taxes paid or payable as a
result thereof.
 
  "Net Present Value" means, with respect to any proved hydrocarbon reserves,
the discounted future net revenues associated with such reserves, determined
in accordance with the rules and regulations (including interpretations
thereof) of the SEC in effect on the Issue Date.
 
  "Net Working Capital" means (a) all current assets of the Company and its
Restricted Subsidiaries minus (b) all current liabilities of the Company and
its Restricted Subsidiaries, except current liabilities included in
Indebtedness, determined in accordance with GAAP.
 
                                      85
<PAGE>
 
  "Offering Memorandum" means the Offering Memorandum dated October 25, 1996,
in connection with the sale of the Outstanding Notes.
 
  "Oil and Gas Business" means the business of the exploration for, and
exploitation, development, acquisition, production, processing (but not
refining), marketing, storage and transportation of, hydrocarbons, and other
related energy and natural resource businesses (including oil and gas services
businesses related to the foregoing).
 
  "Oil and Gas Hedging Contract" means any oil and gas purchase or hedging
agreement, and other agreement or arrangement, in each case, that is designed
to provide protection against oil and gas price fluctuations.
 
  "Permitted Business Investment" means any Investment made in the ordinary
course of, and of a nature that is or shall have become customary in, the Oil
and Gas Business as a means of actively exploiting, exploring for, acquiring,
developing, producing, processing, gathering, marketing or transporting oil
and gas through agreements, transactions, interests or arrangements which
permit one to share risks or costs, comply with regulatory requirements
regarding local ownership or satisfy other objectives customarily achieved
through the conduct of Oil and Gas Business jointly with third parties,
including (i) ownership interests in oil and gas properties, processing
facilities, gathering systems or ancillary real property interests and (ii)
Investments in the form of or pursuant to operating agreements, processing
agreements, farm-in agreements, farm-out agreements, development agreements,
area of mutual interest agreements, qunitization agreements, pooling
agreements, joint bidding agreements, service contracts, joint venture
agreements, partnership agreements (whether general or limited), subscription
agreements, stock purchase agreements and other similar agreements with third
parties.
 
  "Permitted Holders" means (i) the members of Contour Production Company
L.L.C., a Delaware limited liability company ("Contour"), as of the Issue Date
(the "Contour Group"), (ii) Contour, so long as Contour is controlled (as
defined in the definition of "Affiliate" above), directly or indirectly, by
the Contour Group, (iii) officers, principals, employees, direct or indirect
owners or Affiliates of Persons described in clauses (i) or (ii), (iv) Persons
who beneficially own Voting Stock of the Company on the Issue Date and (v)
officers or employees of the Company or any of its Subsidiaries as of the
Issue Date.
 
  "Permitted Investment" means an Investment by the Company or any Restricted
Subsidiary in (i) a Restricted Subsidiary or a Person that will, upon the
making of such Investment, become a Restricted Subsidiary; provided, however,
that the primary business of such Restricted Subsidiary is an Oil and Gas
Business; (ii) another Person if as a result of such Investment such other
Person is merged or consolidated with or into, or transfers or conveys all or
substantially all its assets to, the Company or a Restricted Subsidiary;
provided, however, that such Person's primary business is an Oil and Gas
Business; (iii) Temporary Cash Investments; (iv) receivables owing to the
Company or any Restricted Subsidiary if created or acquired in the ordinary
course of business and payable or dischargeable in accordance with customary
trade terms; provided, however, that such trade terms may include such
concessionary trade terms as the Company or any such Restricted Subsidiary
deems reasonable under the circumstances; (v) payroll, travel and similar
advances to cover matters that are expected at the time of such advances
ultimately to be treated as expenses for accounting purposes and that are made
in the ordinary course of business; (vi) loans or advances to employees made
in the ordinary course of business; (vii) stock, obligations or securities
received in settlement of debts created in the ordinary course of business and
owing to the Company or any Restricted Subsidiary or in satisfaction of
judgments; (viii) any Person to the extent such Investment represents the non-
cash portion of the consideration received for an Asset Disposition as
permitted pursuant to the covenant described under "--Certain Covenants--
Limitation on Sales of Assets and Subsidiary Stock" and (ix) Permitted
Business Investments.
 
  "Permitted Liens" means, with respect to any Person, (a) pledges or deposits
by such Person under worker's compensation laws, unemployment insurance laws
or similar legislation, or good faith deposits in connection with bids,
tenders, contracts (other than for the payment of Indebtedness) or leases to
which such Person is a party, or deposits to secure public or statutory
obligations of such Person or deposits of cash or United
 
                                      86
<PAGE>
 
States government bonds to secure surety or appeal bonds to which such Person
is a party, or deposits as security for contested taxes or import duties or
for the payment of rent, in each case Incurred in the ordinary course of
business; (b) Liens imposed by law, such as carriers', warehousemen's and
mechanics' Liens, in each case for sums not yet due or being contested in good
faith by appropriate proceedings or other Liens arising out of judgments or
awards against such Person with respect to which such Person shall then be
proceeding with an appeal or other proceedings for review; (c) Liens for
property taxes not yet subject to penalties for non-payment or which are being
contested in good faith and by appropriate proceedings; (d) Liens in favor of
issuers of surety bonds or letters of credit issued pursuant to the request of
and for the account of such Person in the ordinary course of its business;
provided, however, that such letters of credit do not constitute Indebtedness;
(e) minor survey exceptions, minor encumbrances, easements or reservations of,
or rights of others for, licenses, rights of way, sewers, electric lines,
telegraph and telephone lines and other similar purposes, or zoning or other
restrictions as to the use of real property or Liens incidental to the conduct
of the business of such Person or to the ownership of its properties which
were not Incurred in connection with Indebtedness and which do not in the
aggregate materially impair their use in the operation of the business of such
Person; (f) Liens securing Indebtedness Incurred to finance the construction,
purchase or lease of, or repairs, improvements or additions to, property of
such Person (including Liens securing Indebtedness of the pollution control or
revenue bond type); provided, however, that the Lien may not extend to any
other property owned by such Person or any of its Subsidiaries at the time the
Lien is Incurred, and the Indebtedness secured by the Lien may not be Incurred
more than 180 days after the later of the acquisition, completion of
construction, repair, improvement, addition or commencement of full operation
of the property subject to the Lien; (g) Liens to secure Indebtedness
permitted under the provisions described in clause (b)(1) or (b)(8) under
"--Certain Covenants--Limitation on Indebtedness"; provided, however, that any
such Lien securing Indebtedness described in such clause (b)(8) shall be
limited to the hydrocarbons related thereto and any gathering systems utilized
in gathering and transporting such hydrocarbons; (h) Liens existing on the
Issue Date; (i) Liens on property or shares of Capital Stock of another Person
at the time such other Person becomes a Subsidiary of such Person; provided,
however, that such Liens are not created, incurred or assumed in connection
with, or in contemplation of, such other Person becoming such a Subsidiary;
provided further, however, that such Lien may not extend to any other property
owned by such Person or any of its Subsidiaries; (j) Liens on property at the
time such Person or any of its Subsidiaries acquires the property, including
any acquisition by means of a merger or consolidation with or into such Person
or a Subsidiary of such Person; provided, however, that such Liens are not
created, incurred or assumed in connection with, or in contemplation of, such
acquisition; provided further, however, that the Liens may not extend to any
other property owned by such Person or any of its Subsidiaries; (k) Liens
securing Indebtedness or other obligations of a Subsidiary of such Person
owing to such Person or a wholly owned Subsidiary of such Person (or, in the
case of the Company, to a Wholly Owned Subsidiary); (l) Liens securing Hedging
Obligations so long as such Hedging Obligations relate to Indebtedness that
is, and is permitted to be under the Indenture, secured by a Lien on the same
property securing such Hedging Obligations; (m) Liens arising in the ordinary
course of business in favor of the United States, any state thereof, any
foreign country or any department, agency, instrumentality or political
subdivision of any such jurisdiction, to secure partial, progress, advance or
other payments pursuant to any contract or statute; (n) Liens to secure any
Refinancing (or successive Refinancing) as a whole, or in part, of any
Indebtedness secured by any Lien referred to in the foregoing clauses (f),
(h), (i) and (j); provided, however, that (x) such new Lien shall be limited
to all or part of the same property that secured the original Lien (plus
improvements to or on such property) and (y) the Indebtedness secured by such
Lien at such time is not increased to any amount greater than the sum of (A)
the outstanding principal amount or, if greater, committed amount of the
Indebtedness described under clause (f), (h), (i) or (j) at the time the
original Lien became a Permitted Lien and (B) an amount necessary to pay any
fees and expenses, including premiums, related to such Refinancing; (o) Liens
on, related to, properties to secure all or part of the costs incurred in the
ordinary course of business of exploration, drilling, development or operation
thereof; (p) Liens on pipeline or pipeline facilities which arise out of
operation of law; (q) Liens reserved in oil and gas mineral leases for bonus
or rental payments and for compliance with the terms of such leases; and (r)
Liens arising under partnership agreements, oil and gas leases, farm-out
agreements, division orders, contracts for the sale, purchase, exchange,
transportation or processing (but not the refining) of oil, gas or other
hydrocarbons, unitization and pooling declarations and agreements, development
agreements, operating
 
                                      87
<PAGE>
 
agreements, area of mutual interest agreements, and other similar agreements
which are customary in the Oil and Gas Business. Notwithstanding the
foregoing, "Permitted Liens" will not include any Lien described in clause
(f), (i) or (j) above to the extent (A) such Lien applies to any Additional
Assets or Permitted Business Investment acquired directly or indirectly from
Net Available Cash pursuant to clause (a)(i)(B) or paragraph (c) of the
covenant described under "--Certain Covenants--Limitation on Sales of Assets
and Subsidiary Stock" and (B) the fair value of such Additional Assets or
Permitted Business Investment is less than the sum of (x) the amount of
Indebtedness secured by such Lien plus (y) the amount of Net Available Cash so
invested in such Additional Assets or Permitted Business Investment.
 
  "Person" means any individual, corporation, partnership, joint venture,
association, joint-stock company, trust, unincorporated organization,
government or any agency or political subdivision thereof or any other entity.
 
  "Preferred Stock", as applied to the Capital Stock of any corporation, means
Capital Stock of any class or classes (however designated) which is preferred
as to the payment of dividends, or as to the distribution of assets upon any
voluntary or involuntary liquidation or dissolution of such corporation, over
shares of Capital Stock of any other class of such corporation.
 
  "principal" of a Note means the principal of the Note plus the premium, if
any, payable on the Note which is due or overdue or is to become due at the
relevant time.
 
  "Production Payments" means, collectively, Dollar-Denominated Production
Payments and Volumetric Production Payments.
 
  "Programs" means Kelley Partners 1992 Development Drilling Program, a Texas
limited partnership, and Kelley Partners 1994 Development Drilling Program, a
Texas limited partnership, together with Kelley Partners 1992 Development
Drilling Joint Venture, a Texas general partnership, Kelley Partners 1994
Development Drilling Joint Venture, a Texas general partnership, and each of
their respective successors.
 
  "Public Market" means any time when at least 15% of the total issued and
outstanding common stock of the Company has been distributed by means of an
effective registration statement under the Securities Act or sales pursuant to
Rule 144 under the Securities Act.
 
  "Refinance" means, in respect of any Indebtedness, to refinance, extend,
renew, refund, repay, prepay, redeem, defease or retire, or to issue other
Indebtedness in exchange or replacement for, such Indebtedness (including an
Incurrence pursuant to clause (ii) of the first or third paragraph of the
covenant described under "--Certain Covenants--Merger and Consolidation").
"Refinanced" and "Refinancing" shall have correlative meanings.
 
  "Refinancing Indebtedness" means Indebtedness that Refinances any
Indebtedness of the Company or any Restricted Subsidiary existing on the Issue
Date or Incurred in compliance with the Indenture including Indebtedness that
Refinances Refinancing Indebtedness and Indebtedness that is deemed to be
Incurred at the time of a merger or consolidation pursuant to clause (ii) of
the first or third paragraph of the covenant described under "--Certain
Covenants--Merger and Consolidation", provided, however, that (i) such
Refinancing Indebtedness has a Stated Maturity no earlier than the Stated
Maturity of the Indebtedness being Refinanced, (ii) such Refinancing
Indebtedness has an Average Life at the time such Refinancing Indebtedness is
Incurred that is equal to or greater than the Average Life of the Indebtedness
being Refinanced and (iii) such Refinancing Indebtedness has an aggregate
principal amount (or if Incurred with original issue discount, an aggregate
issue price) that is equal to or less than the aggregate principal amount (or
if Incurred with original issue discount, the aggregate accreted value) then
outstanding or committed (plus fees and expenses, including any premium and
defeasance costs) under the Indebtedness being Refinanced; provided further,
however, that Refinancing Indebtedness shall not include (x) Indebtedness of a
Subsidiary (other than a Subsidiary Guarantor) that Refinances Indebtedness of
the Company or (y) Indebtedness of the Company or a Restricted Subsidiary that
Refinances Indebtedness of an Unrestricted Subsidiary.
 
                                      88
<PAGE>
 
  "Representative" means any trustee, agent or representative (if any) for an
issue of Senior Indebtedness of the Company.
 
  "Restricted Payment" with respect to any Person means (i) the declaration or
payment of any dividends or any other distributions of any sort in respect of
its Capital Stock (including any payment in connection with any merger or
consolidation involving such Person) or similar payment to the direct or
indirect holders of its Capital Stock (other than (x) dividends or
distributions payable solely in its Capital Stock (other than Disqualified
Stock), (y) dividends or distributions payable solely to the Company or a
Restricted Subsidiary, and (z) pro rata dividends or other distributions made
by a Subsidiary that is not a Wholly Owned Subsidiary to minority stockholders
(or owners of an equivalent interest in the case of a Subsidiary that is an
entity other than a corporation)), (ii) the purchase, redemption or other
acquisition or retirement for value of any Capital Stock of the Company held
by any Person or of any Capital Stock of a Restricted Subsidiary held by any
Affiliate of the Company (other than a Restricted Subsidiary), including the
exercise of any option to exchange any Capital Stock (other than into Capital
Stock of the Company that is not Disqualified Stock), (iii) the purchase,
repurchase, redemption, defeasance or other acquisition or retirement for
value, prior to scheduled maturity, scheduled repayment or scheduled sinking
fund payment of any Subordinated Obligations (other than the purchase,
repurchase or other acquisition of Subordinated Obligations purchased in
anticipation of satisfying a sinking fund obligation, principal installment or
final maturity, in each case due within one year of the date of acquisition)
or (iv) the making of any Investment in any Person (other than a Permitted
Investment).
 
  "Restricted Subsidiary" means any Subsidiary of the Company that is not an
Unrestricted Subsidiary.
 
  "Sale/Leaseback Transaction" means an arrangement relating to property now
owned or hereafter acquired whereby the Company or a Restricted Subsidiary
transfers such property to a Person and the Company or a Restricted Subsidiary
leases it from such Person.
 
  "SEC" means the Securities and Exchange Commission.
 
  "Secured Indebtedness" means any Indebtedness of the Company secured by a
Lien.
 
  "Senior Indebtedness" means with respect to any Person (i) Indebtedness of
such Person, and all obligations of such Person under any Credit Facilities,
whether outstanding on the Issue Date or thereafter Incurred and (ii) accrued
and unpaid interest (including interest accruing on or after the filing of any
petition in bankruptcy or for reorganization relating such Person to the
extent post-filing interest is allowed in such proceeding) in respect of (A)
indebtedness of such Person for money borrowed and (B) indebtedness evidenced
by notes, debentures, bonds or other similar instruments for the payment of
which such Person is responsible or liable unless, with respect to obligations
described in the immediately preceding clause (i) or (ii), in the instrument
creating or evidencing the same or pursuant to which the same is outstanding,
it is provided that such obligations are subordinate in right of payment to
the Notes or the applicable Subsidiary Guaranty, as the case may be; provided,
however, that Senior Indebtedness shall not include (1) any obligation of such
Person to any Subsidiary of such Person, (2) any liability for Federal, state,
local or other taxes owed or owing by such Person, (3) any accounts payable or
other liability to trade creditors arising in the ordinary course of business
(including guarantees thereof or instruments evidencing such liabilities), (4)
any Indebtedness of such Person (and any accrued and unpaid interest in
respect thereof) which is subordinate or junior in any respect to any other
Indebtedness or other obligation of such Person or (5) that portion of any
Indebtedness which at the time of Incurrence is Incurred in violation of the
Indenture (other than, in the case of the Company or any of its Restricted
Subsidiaries, Indebtedness under any Credit Facility that is Incurred on the
basis of a representation by the Company to the applicable lenders that such
Person is permitted to Incur such Indebtedness under the Indenture).
 
  "Senior Subordinated Indebtedness" means (i) with respect to the Company,
the Notes and any other Indebtedness of the Company that specifically provides
that such Indebtedness is to rank pari passu with the Notes in right of
payment and is not subordinated by its terms in right of payment to any
Indebtedness or other
 
                                      89
<PAGE>
 
obligation of the Company which is not Senior Indebtedness and (ii) with
respect to a Subsidiary Guarantor, the Subsidiary Guaranty of such Subsidiary
Guarantor and any other Indebtedness of such Subsidiary Guarantor that
specifically provides that such Indebtedness is to rank pari passu with such
Subsidiary Guaranty in right of payment and is not subordinated by its terms
in right of payment to any Indebtedness or other obligation of such Subsidiary
Guarantor which is not Senior Indebtedness.
 
  "Significant Subsidiary" means any Restricted Subsidiary that would be a
"Significant Subsidiary" of the Company within the meaning of Rule 1-02 under
Regulation S-X promulgated by the SEC.
 
  "Stated Maturity" means, with respect to any security, the date specified in
such security as the fixed date on which the final payment of principal of
such security is due and payable, including pursuant to any mandatory
redemption provision (but excluding any provision providing for the repurchase
of such security at the option of the holder thereof upon the happening of any
contingency unless such contingency has occurred).
 
  "Subordinated Obligation" means any Indebtedness of the Company (whether
outstanding on the Issue Date or thereafter Incurred) which is subordinate or
junior in right of payment to the Notes pursuant to a written agreement to
that effect.
 
  "Subsidiary" means, in respect of any Person, any corporation, association,
partnership or other business entity of which more than 50% of the total
voting power of shares of Capital Stock or other interests (including
partnership interests) entitled (without regard to the occurrence of any
contingency) to vote in the election of directors, managers or trustees
thereof is at the time owned or controlled, directly or indirectly, by (i)
such Person, (ii) such Person and one or more Subsidiaries of such Person or
(iii) one or more Subsidiaries of such Person.
 
  "Subsidiary Guarantor" means Kelley Operating, Kelley Oil and each other
Restricted Subsidiary of the Company (other than the Programs) that (i) has
total net assets as of the end of the most recent fiscal year (as set forth on
the balance sheet of such Subsidiary prepared in accordance with GAAP) equal
to or greater than the greater of $2.5 million and one percent (1%) of
Adjusted Consolidated Net Tangible Assets as of such date and (ii) delivers a
Subsidiary Guaranty.
 
  "Subsidiary Guaranty" means a Guarantee by a Subsidiary Guarantor of the
Company's obligations with respect to the Notes, which Guarantee will be
subordinated to Senior Indebtedness of such Subsidiary Guarantor on
substantially the same terms as the Notes are subordinated to Senior
Indebtedness of the Company. Any such Subsidiary Guaranty (i) will be
substantially in the form prescribed by the Indenture, (ii) will be limited in
amount to an amount not to exceed the maximum amount that can be guaranteed by
the applicable Subsidiary Guarantor without rendering such Subsidiary
Guaranty, as it relates to such Subsidiary Guarantor, voidable under
applicable law relating to fraudulent conveyance or fraudulent transfer or
similar laws affecting the rights of creditors generally and (iii) will
provide that, upon the sale or other disposition (including by way of
consolidation or merger) of a Subsidiary Guarantor or the sale or disposition
of all or substantially all the assets of a Subsidiary Guarantor permitted by
the Indenture, such Subsidiary Guarantor shall be released from all its
obligations under its Subsidiary Guaranty.
 
  "Temporary Cash Investments" means any of the following: (i) any investment
in direct obligations of the United States of America or any agency thereof or
obligations guaranteed by the United States of America or any agency thereof,
(ii) investments in time deposit accounts, certificates of deposit and money
market deposits maturing within 180 days of the date of acquisition thereof
issued by a bank or trust company which is organized under the laws of the
United States of America, any state thereof or any foreign country recognized
by the United States, and which bank or trust company has capital, surplus and
undivided profits aggregating in excess of $50.0 million (or the foreign
currency equivalent thereof) and has outstanding debt which is rated "A" (or
such similar equivalent rating) or higher by at least one nationally
recognized statistical rating organization (as defined in Rule 436 under the
Securities Act) or any money-market fund sponsored by a registered broker
dealer or mutual fund distributor, (iii) repurchase obligations with a term of
not more than 30 days for underlying securities of the
 
                                      90
<PAGE>
 
types described in clause (i) above entered into with a bank meeting the
qualifications described in clause (ii) above, (iv) investments in commercial
paper, maturing not more than 180 days after the date of acquisition, issued
by a Person (other than an Affiliate of the Company) organized and in
existence under the laws of the United States of America or any foreign
country recognized by the United States of America with a rating at the time
as of which any investment therein is made of "P-2" (or higher) according to
Moody's Investors Service, Inc. or "A-2" (or higher) according to Standard and
Poor's Ratings Group, and (v) investments in securities with maturities of six
months or less from the date of acquisition issued or fully guaranteed by any
state, commonwealth or territory of the United States of America, or by any
political subdivision or taxing authority thereof, and rated at least "A" by
Standard & Poor's Ratings Group or "A" by Moody's Investors Service, Inc.
 
  "Total Assets" of the Company means the total consolidated assets of the
Company and its Restricted Subsidiaries, as shown on the most recent balance
sheet of the Company.
 
  "Unrestricted Subsidiary" means (i) any Subsidiary of the Company that at
the time of determination shall be designated an Unrestricted Subsidiary by
the Board of Directors in the manner provided below and (ii) any Subsidiary of
an Unrestricted Subsidiary. The Board of Directors may designate any
Subsidiary of the Company (including any newly acquired or newly formed
Subsidiary) to be an Unrestricted Subsidiary unless such Subsidiary or any of
its Subsidiaries owns any Capital Stock or Indebtedness of, or holds any Lien
on any property of, the Company or any other Subsidiary of the Company that is
not a Subsidiary of the Subsidiary to be so designated; provided, however,
that either (A) the Subsidiary to be so designated has total assets of $1,000
or less or (B) if such Subsidiary has assets greater than $1,000, such
designation would be permitted under the covenant described under "--Certain
Covenants--Limitation on Restricted Payments". The Board of Directors may
designate any Unrestricted Subsidiary to be a Restricted Subsidiary; provided,
however, that immediately after giving effect to such designation (x) the
Company could Incur $1.00 of additional Indebtedness under paragraph (a) of
the covenant described under "--Certain Covenants--Limitation on Indebtedness"
and (y) no Default shall have occurred and be continuing. Any such designation
by the Board of Directors shall be evidenced by the Company to the Trustee by
promptly filing with the Trustee a copy of the board resolution giving effect
to such designation and an Officers' Certificate certifying that such
designation complied with the foregoing provisions.
 
  "U.S. Government Obligations" means direct obligations (or certificates
representing an ownership interest in such obligations) of the United States
of America (including any agency or instrumentality thereof) for the payment
of which the full faith and credit of the United States of America is pledged
and which are not callable at the issuer's option.
 
  "Volumetric Production Payments" means production payment obligations
recorded as deferred revenue in accordance with GAAP, together with all
undertakings and obligations in connection therewith.
 
  "Voting Stock" of a Person means all classes of Capital Stock or other
interests (including partnership interests) of such Person then outstanding
and normally entitled (without regard to the occurrence of any contingency) to
vote in the election of directors, managers or trustees thereof.
 
  "Wholly Owned Subsidiary" means a Restricted Subsidiary all the Capital
Stock of which (other than directors' qualifying shares and shares held by
other Persons to the extent such shares are required by applicable law to be
held by a Person other than the Company or a Restricted Subsidiary) is owned
by the Company or one or more Wholly Owned Subsidiaries.
 
CERTAIN COVENANTS
 
  The Indenture contains covenants including, among others, the following:
 
    Limitation on Indebtedness. (a) The Company shall not, and shall not
  permit any Restricted Subsidiary to, Incur, directly or indirectly, any
  Indebtedness; provided, however, that the Company or a Subsidiary Guarantor
  may Incur Indebtedness if, on the date of such Incurrence and after giving
  effect thereto, the
 
                                      91
<PAGE>
 
  Consolidated Coverage Ratio equals or exceeds (i) 2.0 to 1.0, if such
  Indebtedness is Incurred on or prior to September 30, 1999, (ii) 2.25 to
  1.0, if such Indebtedness is Incurred after September 30, 1999 and on or
  prior to September 30, 2001, and (iii) 2.5 to 1.0 if such Indebtedness is
  Incurred after September 30, 2001.
 
    (b) Notwithstanding the foregoing paragraph (a), the Company and any
  Restricted Subsidiary may Incur the following Indebtedness:
 
       (1) Indebtedness of the Company Incurred pursuant to any Credit
           Facility, so long as the aggregate principal amount of all
           Indebtedness outstanding under all Credit Facilities does not,
           at any one time, exceed the aggregate amount of borrowing
           availability as of such date under all Credit Facilities that
           determine availability on the basis of a borrowing base or other
           asset-based calculation; provided, however, that in no event
           shall the aggregate principal amount of Indebtedness Incurred
           pursuant to this clause (1) outstanding at any one time exceed
           $250.0 million; provided further, however, that if the Company
           or a Subsidiary Guarantor Incurs any Indebtedness pursuant to
           this clause (1) that would cause the total principal amount of
           Indebtedness outstanding under this clause (1) to exceed an
           amount equal to $150.0 million (less the aggregate amount of all
           Net Available Cash of Asset Dispositions applied to reduce
           Senior Indebtedness pursuant to clause (a)(i)(A) of the covenant
           described under the caption "--Limitation on Sales of Assets and
           Subsidiary Stock"), the Consolidated Coverage Ratio on the date
           of such Incurrence must be at least 2.0 to 1.0;
 
       (2) Indebtedness owed to and held by the Company or a Wholly Owned
           Subsidiary; provided, however, that any subsequent issuance or
           transfer of any Capital Stock which results in any such Wholly
           Owned Subsidiary ceasing to be a Wholly Owned Subsidiary or any
           subsequent transfer of such Indebtedness (other than to the
           Company or another Wholly Owned Subsidiary) shall be deemed, in
           each case, to constitute the Incurrence of such Indebtedness by
           the issuer thereof;
 
       (3) The Notes and the Subsidiary Guaranties;
 
       (4) Indebtedness outstanding on the Issue Date (other than
           Indebtedness described in clause (1), (2) or (3) of this
           covenant);
 
       (5) Indebtedness or Preferred Stock of a Restricted Subsidiary
           Incurred and outstanding on or prior to the date on which such
           Restricted Subsidiary was acquired by the Company (other than
           Indebtedness or Preferred Stock Incurred in connection with, or
           to provide all or any portion of the funds or credit support
           utilized to consummate, the transaction or series of related
           transactions pursuant to which such Restricted Subsidiary became
           a Restricted Subsidiary or was acquired by the Company);
           provided, however, that on the date of such acquisition and
           after giving effect thereto, the Consolidated Coverage Ratio
           equals or exceeds (i) 1.8 to 1.0, if such Indebtedness is
           Incurred on or prior to September 30, 1999, (ii) 2.05 to 1.0, if
           such Indebtedness is Incurred after September 30, 1999 and on or
           prior to September 30, 2001, and (iii) 2.3 to 1.0, if such
           Indebtedness is Incurred after September 30, 2001.
 
       (6) Refinancing Indebtedness in respect of Indebtedness Incurred
           pursuant to paragraph (a) or pursuant to clause (3), (4), (5)
           above, this clause (6) or clause (7) or (13) below; provided,
           however, that to the extent such Refinancing Indebtedness
           directly or indirectly Refinances Indebtedness or Preferred
           Stock of a Restricted Subsidiary described in clause (5), such
           Refinancing Indebtedness shall be Incurred only by such
           Restricted Subsidiary or the Company;
 
       (7) Indebtedness of the Company or a Restricted Subsidiary
           represented by Capital Lease Obligations, mortgage financings or
           purchase money obligations, in each case Incurred for the
           purpose of financing all or any part of the purchase price or
           cost of construction or
 
                                      92
<PAGE>
 
          improvement of property used in an Oil and Gas Business and in
          each case Incurred no later than 365 days after the date of such
          acquisition or the date of completion of such construction or
          improvement; provided, however, that the principal amount of any
          Indebtedness Incurred pursuant to this clause (7) in any single
          calendar year shall not exceed $15.0 million;
 
       (8) Indebtedness with respect to Production Payments; provided,
          however, that any such Indebtedness shall be Limited Recourse
          Indebtedness; provided further, however, that the Net Present
          Value of the reserves related to such Production Payments shall
          not exceed 30% of the Total Assets of the Company at the time of
          Incurrence;
 
       (9) Indebtedness consisting of Interest Rate Agreements directly
          related to Indebtedness permitted to be Incurred by the Company
          and its Restricted Subsidiaries pursuant to the Indenture;
 
      (10) Indebtedness under Oil and Gas Hedging Contracts and Currency
          Agreements entered into in the ordinary course of business for the
          purpose of limiting risks that arise in the ordinary course of
          business of the Company;
 
      (11) Indebtedness in respect of letters of credit issued for the
          benefit of the Company or any of its Restricted Subsidiaries to
          the extent they are issued in connection with the ordinary course
          of business of the Company and its Restricted Subsidiaries,
          Incurred in an aggregate principal amount which, when taken
          together with the principal amount of all other Indebtedness
          Incurred pursuant to this clause (11) and then outstanding, does
          not exceed $15.0 million;
 
      (12) Indebtedness of the Company or a Restricted Subsidiary Incurred
          to finance capital expenditures (or Refinancings thereof) in an
          aggregate principal amount which, when taken together with the
          principal amount of all other Indebtedness Incurred pursuant to
          this clause (12) and then outstanding, does not exceed $10.0
          million;
 
      (13) Indebtedness of the Company or a Restricted Subsidiary Incurred
          for the purpose of financing all or any part of the cost of
          acquiring oil and gas reserves, another Person (other than a
          Person that was, immediately prior to such acquisition, a
          Subsidiary of the Company) engaged in the Oil and Gas Business or
          all or substantially all the assets of such a Person; provided,
          however, that on the date of such Incurrence and after giving
          effect thereto, the Consolidated Coverage Ratio equals or exceeds
          (i) 1.8 to 1.0, if such Indebtedness is Incurred on or prior to
          September 30, 1999, (ii) 2.05 to 1.0, if such Indebtedness is
          Incurred after September 30, 1999 and on or prior to September 30,
          2001, and (iii) 2.3 to 1.0 if such Indebtedness is Incurred after
          September 30, 2001; and
 
      (14) Indebtedness in an aggregate principal amount which, together
          with the principal amount of all other Indebtedness of the Company
          and its Restricted Subsidiaries outstanding on the date of such
          Incurrence (other than Indebtedness permitted by clauses (1)
          through (13) above or paragraph (a)) does not exceed the greater
          of 6% of Adjusted Consolidated Net Tangible Assets as of the end
          of the most recent fiscal year ending at least 90 days prior to
          the date of such Incurrence and $15.0 million.
 
    (c) Notwithstanding the foregoing, the Company shall not Incur any
  Indebtedness pursuant to the foregoing paragraph (b) if the proceeds
  thereof are used, directly or indirectly, to Refinance any Subordinated
  Obligations unless such Indebtedness shall be subordinated to the Notes to
  at least the same extent as such Subordinated Obligations; provided,
  however, that this paragraph (c) shall not prohibit the Company from
  refinancing at maturity any of its Subordinated Obligations outstanding on
  the Issue Date; provided, further, however, that this paragraph (c) shall
  not prohibit the Refinancing of the Company's 7 7/8% Convertible
  Subordinated Notes due 1999, provided that within 30 days thereafter the
  Company receives $27.0 million Net Cash Proceeds from the exercise of the
  Contour Option.
 
                                      93
<PAGE>
 
    (d) For purposes of determining compliance with the foregoing covenant,
  (i) in the event that an item of Indebtedness meets the criteria of more
  than one of the types of Indebtedness described above, the Company, in its
  sole discretion, will classify such item of Indebtedness and only be
  required to include the amount and type of such Indebtedness in one of the
  above clauses and (ii) an item of Indebtedness may be divided and
  classified in more than one of the types of Indebtedness described above.
 
    (e) Notwithstanding paragraphs (a) and (b) above, the Company shall not,
  and the Company shall not permit any Subsidiary Guarantor to, Incur (i) any
  Indebtedness if such Indebtedness is subordinate or junior in ranking in
  any respect to any Senior Indebtedness of such Person, unless such
  Indebtedness is Senior Subordinated Indebtedness of such Person or is
  expressly subordinated in right of payment to Senior Subordinated
  Indebtedness of such Person or (ii) any Secured Indebtedness that is not
  Senior Indebtedness of such Person unless contemporaneously therewith
  effective provision is made to secure the Notes or the relevant Subsidiary
  Guaranty equally and ratably with such Secured Indebtedness for so long as
  such Secured Indebtedness is secured by a Lien.
 
  Limitation on Restricted Payments. (a) The Company shall not, and shall not
permit any Restricted Subsidiary, directly or indirectly, to make a Restricted
Payment if at the time the Company or such Restricted Subsidiary makes such
Restricted Payment: (1) a Default shall have occurred and be continuing (or
would result therefrom); (2) the Company is not able to Incur an additional
$1.00 of Indebtedness pursuant to paragraph (a) of the covenant described
under "--Limitation on Indebtedness"; or (3) the aggregate amount of such
Restricted Payment and all other Restricted Payments since the Issue Date
would exceed the sum of: (A) 50% of the Consolidated Net Income accrued during
the period (treated as one accounting period) from the beginning of the fiscal
quarter immediately following the fiscal quarter during which the Notes are
originally issued to the end of the most recent fiscal quarter ending at least
45 days prior to the date of such Restricted Payment (or, in case such
Consolidated Net Income shall be a deficit, minus 100% of such deficit); (B)
the aggregate Net Cash Proceeds received by the Company from the issuance or
sale of its Capital Stock (other than Disqualified Stock) subsequent to the
Issue Date (other than an issuance or sale to a Subsidiary of the Company and
other than an issuance or sale to an employee stock ownership plan or to a
trust established by the Company or any of its Subsidiaries for the benefit of
their employees); (C) the aggregate Net Cash Proceeds received by the Company
from the issue or sale subsequent to the Issue Date of its Capital Stock
(other than Disqualified Stock) to an employee stock ownership plan; provided,
however, that if such employee stock ownership plan incurs any Indebtedness
with respect thereto, such aggregate amount shall be limited to an amount
equal to any increase in the Consolidated Net Worth of the Company resulting
from principal repayments made by such employee stock ownership plan with
respect to such Indebtedness; (D) the amount by which Indebtedness of the
Company is reduced on the Company's balance sheet upon the conversion or
exchange (other than by a Subsidiary of the Company) subsequent to the Issue
Date, of any Indebtedness of the Company convertible or exchangeable for
Capital Stock (other than Disqualified Stock) of the Company (less the amount
of any cash, or the fair value of any other property, distributed by the
Company upon such conversion or exchange); and (E) an amount equal to the sum
of (i) the net reduction in Investments in Unrestricted Subsidiaries resulting
from dividends, repayments of loans or advances or other transfers of assets,
in each case to the Company or any Restricted Subsidiary from Unrestricted
Subsidiaries, and (ii) the portion (proportionate to the Company's equity
interest in such Subsidiary) of the fair market value of the net assets of an
Unrestricted Subsidiary at the time such Unrestricted Subsidiary is designated
a Restricted Subsidiary; provided, however, that the foregoing sum shall not
exceed, in the case of any Unrestricted Subsidiary, the amount of Investments
previously made (and treated as a Restricted Payment) by the Company or any
Restricted Subsidiary in such Unrestricted Subsidiary.
 
  (b) The provisions of the foregoing paragraph (a) shall not prohibit: (i)
any purchase or redemption of Capital Stock or Subordinated Obligations of the
Company made by exchange for, or out of the proceeds of the substantially
concurrent sale of, Capital Stock of the Company (other than Disqualified
Stock and other than Capital Stock issued or sold to a Subsidiary of the
Company or an employee stock ownership plan or to a trust established by the
Company or any of its Subsidiaries for the benefit of their employees);
provided, however, that (A) such purchase or redemption shall be excluded in
the calculation of the amount of Restricted Payments
 
                                      94
<PAGE>
 
and (B) the Net Cash Proceeds from such sale shall be excluded from the
calculation of amounts under clause (3)(B) of paragraph (a) above (but only to
the extent that such Net Cash Proceeds were used to purchase or redeem such
Capital Stock as provided in this clause (i)); (ii) any purchase, repurchase,
redemption, defeasance or other acquisition or retirement for value of
Subordinated Obligations made by exchange for, or out of the proceeds of the
substantially concurrent sale of, Indebtedness of the Company which is
permitted to be Incurred pursuant to the covenant described under
"--Limitation on Indebtedness"; provided, however, that such purchase,
repurchase, redemption, defeasance or other acquisition or retirement for
value shall be excluded in the calculation of the amount of Restricted
Payments; (iii) dividends paid within 60 days after the date of declaration
thereof if at such date of declaration such dividend would have complied with
this covenant; provided, however, that at the time of payment of such
dividend, no other Default shall have occurred and be continuing (or result
therefrom); provided further, however, that such dividend shall be included in
the calculation of the amount of Restricted Payments; (iv) the repurchase of
shares of, or options to purchase shares of, common stock of the Company or
any of its Subsidiaries from employees, former employees, directors or former
directors of the Company or any of its Subsidiaries (or permitted transferees
of such employees, former employees, directors or former directors), pursuant
to the terms of the agreements (including employment agreements) or plans (or
amendments thereto) approved by the Board of Directors under which such
individuals purchase or sell or are granted the option to purchase or sell,
shares of such common stock; provided, however, that the aggregate amount of
such repurchases shall not exceed $1.0 million in any calendar year and $6.0
million in the aggregate; provided further, however, that such repurchases
shall be excluded in the calculation of the amount of Restricted Payments; (v)
amounts paid to holders of the Company's Convertible Exchangeable Preferred
Stock to the extent such amounts do not exceed the amount of dividends in
arrears through and including November 1, 1996 in respect of such Convertible
Exchangeable Preferred Stock; provided, however, that at the time of payment
of such amounts, no Default shall have occurred and be continuing (or result
therefrom); provided further, however, that the amount of such amounts shall
be excluded in the calculation of the amount of Restricted Payments; (vi)
dividends paid from time to time in respect of the Company's Convertible
Exchangeable Preferred Stock (other than amounts permitted by clause (v)
above); provided, however, that at the time of payment of such dividends, no
Default shall have occurred and be continuing (or result therefrom); provided
further, however, that the amount of such dividends shall be included in the
calculation of the amount of Restricted Payments; or (vii) other Restricted
Payments in an aggregate amount not to exceed $10.0 million; provided,
however, that such Restricted Payment shall be excluded in the calculation of
the amount of Restricted Payments.
 
  Limitation on Restrictions on Distributions from Restricted Subsidiaries.
The Company shall not, and shall not permit any Restricted Subsidiary to,
create or otherwise cause or permit to exist or become effective any
consensual encumbrance or restriction on the ability of any Restricted
Subsidiary (a) to pay dividends or make any other distributions on its Capital
Stock or pay any Indebtedness owed to the Company or a Restricted Subsidiary,
(b) to make any loans or advances to the Company or a Restricted Subsidiary or
(c) to transfer any of its property or assets to the Company or a Restricted
Subsidiary, except: (i) any encumbrance or restriction pursuant to an
agreement in effect at or entered into on the Issue Date; (ii) any encumbrance
or restriction with respect to a Restricted Subsidiary pursuant to an
agreement relating to any Indebtedness Incurred by such Restricted Subsidiary
on or prior to the date on which such Restricted Subsidiary was acquired by
the Company (other than Indebtedness Incurred as consideration in, or to
provide all or any portion of the funds or credit support utilized to
consummate, the transaction or series of related transactions pursuant to
which such Restricted Subsidiary became a Restricted Subsidiary or was
acquired by the Company) and outstanding on such date; (iii) any encumbrance
or restriction pursuant to an agreement effecting a Refinancing of
Indebtedness Incurred pursuant to an agreement referred to in clause (i) or
(ii) of this covenant or this clause (iii) or contained in any amendment to an
agreement referred to in clause (i) or (ii) of this covenant or this clause
(iii); provided, however, that the encumbrances and restrictions with respect
to such Restricted Subsidiary contained in any such refinancing agreement or
amendment are no less favorable to the Noteholders than encumbrances and
restrictions with respect to such Restricted Subsidiary contained in such
agreements; (iv) any such encumbrance or restriction consisting of customary
nonassignment provisions in leases governing leasehold interests to the extent
such provisions restrict the transfer of the lease or the property leased
thereunder; (v) in the case of clause (c) above,
 
                                      95
<PAGE>
 
restrictions contained in security agreements or mortgages securing
Indebtedness of a Restricted Subsidiary to the extent such restrictions
restrict the transfer of the property subject to such security agreements or
mortgages; and (vi) any restriction with respect to a Restricted Subsidiary
imposed pursuant to an agreement entered into for the sale or disposition of
all or substantially all the Capital Stock or assets of such Restricted
Subsidiary pending the closing of such sale or disposition.
 
  Limitation on Sales of Assets and Subsidiary Stock. (a) In the event and to
the extent that the Net Available Cash received by the Company or any
Restricted Subsidiary from one or more Asset Dispositions occurring on or
after the Issue Date in any period of 12 consecutive months exceeds 10% of
Adjusted Consolidated Assets as of the beginning of such 12-month period, then
the Company shall (i) within 180 days (in the case of (A) below) or 360 days
(in the case of (B) below) after the date such Net Available Cash so received
exceeds such 10% of Adjusted Consolidated Assets (A) apply an amount equal to
such excess Net Available Cash to repay Senior Indebtedness or Indebtedness of
a Restricted Subsidiary, in each case owing to a Person other than the Company
or any Affiliate of the Company or (B) invest an equal amount, or the amount
not so applied pursuant to clause (A), in Additional Assets or a Permitted
Business Investment or (ii) apply such excess Net Available Cash (to the
extent not applied pursuant to clause (i)) as provided in the following
paragraphs of the covenant described hereunder. The amount of such excess Net
Available Cash required to be applied during the applicable period and not
applied as so required by the end of such period shall constitute "Excess
Proceeds".
 
  If, as of the first day of any calendar month, the aggregate amount of
Excess Proceeds not theretofore subject to an Excess Proceeds Offer (as
defined below) totals at least $10.0 million, the Company must, not later than
the fifteenth Business Day of such month, make an offer (an "Excess Proceeds
Offer") to purchase from the Holders on a pro rata basis an aggregate
principal amount of Notes equal to the Excess Proceeds (rounded down to the
nearest multiple of $1,000) on such date, at a purchase price equal to 100% of
the principal amount of such Notes, plus, in each case, accrued interest (if
any) to the date of purchase (the "Excess Proceeds Payment").
 
  The Company will comply, to the extent applicable, with the requirements of
Section 14(e) of the Exchange Act and any other securities laws or regulations
thereunder in the event that such Excess Proceeds are received by the Company
under the covenant described hereunder and the Company is required to
repurchase Notes as described above. To the extent that the provisions of any
securities laws or regulations conflict with the provisions of the covenant
described hereunder, the Company shall comply with the applicable securities
laws and regulations and shall not be deemed to have breached its obligations
under the covenant described hereunder by virtue thereof.
 
  (b) In the event of the transfer of substantially all (but not all) the
property and assets of the Company as an entirety to a Person in a transaction
permitted by the covenant described under "--Merger and Consolidation", the
Successor Company (as defined therein) shall be deemed to have sold the
properties and assets of the Company not so transferred for purposes of the
covenant described hereunder, and shall comply with the provisions of the
covenant described hereunder with respect to such deemed sale as if it were an
Asset Disposition and the Successor Company shall be deemed to have received
Net Available Cash in an amount equal to the fair market value (as determined
in good faith by the Board of Directors) of the properties and assets not so
transferred or sold.
 
  (c) In the event of an Asset Disposition by the Company or any Restricted
Subsidiary that consists of a sale of hydrocarbons and results in Production
Payments, the Company or such Restricted Subsidiary shall apply an amount
equal to the Net Available Cash received by the Company or such Restricted
Subsidiary to (i) reduce Senior Indebtedness of the Company or Indebtedness of
a Restricted Subsidiary, in each case owing to a Person other than the Company
or any Affiliate of the Company, within 180 days after the date such Net
Available Cash is so received, or (ii) invest in Additional Assets or a
Permitted Business Investment within 360 days after the date such Net
Available Cash is so received.
 
 
                                      96
<PAGE>
 
  Limitation on Affiliate Transactions. (a) The Company shall not, and shall
not permit any Restricted Subsidiary to, enter into or permit to exist any
transaction (including the purchase, sale, lease or exchange of any property,
employee compensation arrangements or the rendering of any service) with any
Affiliate of the Company (an "Affiliate Transaction") unless the terms thereof
(1) are no less favorable to the Company or such Restricted Subsidiary than
those that could be obtained at the time of such transaction in arm's-length
dealings with a Person who is not such an Affiliate, (2) if such Affiliate
Transaction involves an amount in excess of $1.0 million, is set forth in
writing and has been approved by a majority of the members of the Board of
Directors having no personal stake in such Affiliate Transaction or (3) if
such Affiliate Transaction involves an amount in excess of $10.0 million, has
been determined by a nationally recognized investment banking firm to be fair,
from a financial standpoint, to the Company and its Restricted Subsidiaries.
 
  (b) The provisions of the foregoing paragraph (a) shall not prohibit (i) any
sale of hydrocarbons or other mineral products or the entering into or
performance of Oil and Gas Hedging Contracts, gas gathering, transportation or
processing contracts or oil or natural gas marketing or exchange contracts, in
each case, in the ordinary course of business, so long as the terms of any
such transaction are approved by a majority of the members of the Board of
Directors who are disinterested with respect to such transaction as being the
most favorable of at least (x) two bids, quotes or proposals, at least one of
which is from a Person that is not an Affiliate of the Company (in the event
that the Company determines in good faith that it is able to obtain only two
bids, quotes or proposals with respect to such transaction) or (y) three bids,
quotes or proposals, at least two of which are from Persons that are not
Affiliates of the Company (in all other circumstances), (ii) the sale to an
Affiliate of the Company of Capital Stock of the Company that does not
constitute Disqualified Stock, (iii) transactions contemplated by any
employment agreement or other compensation plan or arrangement entered into by
the Company or any of its Restricted Subsidiaries in the ordinary course of
business and consistent with industry practice, (iv) transactions between or
among the Company and its Restricted Subsidiaries, (v) Restricted Payments and
Permitted Investments that are permitted by the provisions of the Indenture
described above under the caption "--Limitation on Restricted Payments", (vi)
the transactions described in the Offering Memorandum under the caption
"Certain Transactions" and (vii) loans or advances to employees in the
ordinary course of business and approved by the Company's Board of Directors
in an aggregate principal amount not to exceed $1.0 million outstanding at any
one time.
 
  Change of Control. (a) Upon the occurrence of a Change of Control, each
Holder shall have the right to require that the Company repurchase such
Holder's Notes at a purchase price in cash equal to 101% of the principal
amount thereof plus accrued and unpaid interest, if any, to the date of
purchase (subject to the right of Holders of record on the relevant record
date to receive interest on the relevant interest payment date), in accordance
with the terms contemplated in paragraph (b) below.
 
  (b) Within 30 days following any Change of Control, the Company shall mail a
notice to each Holder with a copy to the Trustee stating: (1) that a Change of
Control has occurred and that such Holder has the right to require the Company
to purchase such Holder's Notes at a purchase price in cash equal to 101% of
the principal amount thereof plus accrued and unpaid interest, if any, to the
date of purchase (subject to the right of Holders of record on the relevant
record date to receive interest on the relevant interest payment date); (2)
the circumstances and relevant facts regarding such Change of Control
(including information with respect to pro forma historical income, cash flow
and capitalization after giving effect to such Change of Control); (3) the
repurchase date (which shall be no earlier than 30 days nor later than 60 days
from the date such notice is mailed); and (4) the instructions determined by
the Company, consistent with the covenant described hereunder, that a Holder
must follow in order to have its Notes purchased.
 
  (c) The Company shall comply, to the extent applicable, with the
requirements of Section 14(e) of the Exchange Act and any other securities
laws or regulations in connection with the repurchase of Notes pursuant to
this covenant described hereunder. To the extent that the provisions of any
securities laws or regulations conflict with the provisions of the covenant
described hereunder, the Company shall comply with the applicable securities
laws and regulations and shall not be deemed to have breached its obligations
under the covenant described hereunder by virtue thereof.
 
                                      97
<PAGE>
 
  The Change of Control purchase feature is a result of negotiations between
the Company and the Placement Agents. Management has no present intention to
engage in a transaction involving a Change of Control, although it is possible
that the Company would decide to do so in the future. Subject to the
limitations discussed below, the Company could, in the future, enter into
certain transactions, including acquisitions, refinancings or other
recapitalizations, that would not constitute a Change of Control under the
Indenture, but that could increase the amount of indebtedness outstanding at
such time or otherwise affect the Company's capital structure or credit
ratings. Restrictions on the ability of the Company to incur additional
Indebtedness are contained in the covenants described under "--Limitation on
Indebtedness", "--Limitation on Liens" and "--Limitation on Sale/Leaseback
Transactions". Such restrictions can only be waived with the consent of the
holders of a majority in principal amount of the Notes then outstanding.
Except for the limitations contained in such covenants, however, the Indenture
will not contain any covenants or provisions that may afford holders of the
Notes protection in the event of a highly leveraged transaction.
 
  For purposes of clause (iii) of the definition of "Change of Control"
included in "--Certain Definitions" and in the Indenture, under New York law,
the governing law of the Indenture, there is no consistently predictable
measure of what constitutes the sale of "all or substantially all" of the
property of the Company. As a result, the Holders and the Company may not
agree on whether a particular transaction constitutes the sale of "all or
substantially all" of the property of the Company such that the Company would
be obligated under the Indenture to make an offer to purchase the Notes, in
which case the Holders may have the burden of proving that the transaction
constitutes the sale of "all or substantially all" of the property of the
Company.
 
  The New Credit Agreement prohibits the Company from purchasing any Notes and
also provides that the occurrence of certain change of control events with
respect to the Company would constitute a default thereunder. In the event a
Change of Control occurs at a time when the Company is prohibited from
purchasing Notes, the Company could seek the consent of its lenders to the
purchase of Notes or could attempt to refinance the borrowings that contain
such prohibition. If the Company does not obtain such a consent or repay such
borrowings, the Company will remain prohibited from purchasing Notes. In such
case, the Company's failure to purchase tendered Notes would constitute an
Event of Default under the Indenture which would, in turn, constitute a
default under the Credit Agreement. In such circumstances, the subordination
provisions in the Indenture would likely restrict payment to the Holders of
Notes.
 
  Future indebtedness of the Company may contain prohibitions on the
occurrence of certain events that would constitute a Change of Control or
require such indebtedness to be repurchased upon a Change of Control.
Moreover, the exercise by the holders of their right to require the Company to
repurchase the Notes could cause a default under such indebtedness, even if
the Change of Control itself does not, due to the financial effect of such
repurchase on the Company. Finally, the Company's ability to pay cash to the
holders of Notes following the occurrence of a Change of Control may be
limited by the Company's then existing financial resources. There can be no
assurance that sufficient funds will be available when necessary to make any
required repurchases.
 
  The provisions under the Indenture relating to the Company's obligation to
make an offer to repurchase the Notes as a result of a Change of Control may
be waived or modified with the written consent of the holders of a majority in
principal amount of the Notes.
 
  The Company will not be required to make an offer to purchase the Notes as a
result of a Change of Control if a third party (i) makes such offer in the
manner, at the times and otherwise in compliance with the requirements set
forth in the Indenture relating to the Company's obligations to make such an
offer and (ii) purchases all Notes validly tendered and not withdrawn under
such an offer.
 
  Limitation on the Sale or Issuance of Capital Stock of Restricted
Subsidiaries. The Company shall not sell or otherwise dispose of any shares of
Capital Stock of a Restricted Subsidiary, and shall not permit any Restricted
Subsidiary, directly or indirectly, to issue or sell or otherwise dispose of
any shares of its Capital Stock except (i) to the Company or a Wholly Owned
Subsidiary, (ii) if, immediately after giving effect to such issuance, sale or
other disposition, the Company and its Restricted Subsidiaries would own less
than 20% of the Voting Stock
 
                                      98
<PAGE>
 
of such Restricted Subsidiary and have no greater economic interest in such
Restricted Subsidiary, (iii) if, immediately after giving effect to such
issuance, sale or other disposition, the Company and its Restricted
Subsidiaries would own greater than 80% of the Voting Stock of such Restricted
Subsidiary and have no lesser economic interest in such Restricted Subsidiary
or (iv) to the extent such shares represent directors' qualifying shares or
shares required by applicable law to be held by a Person other than the
Company or Restricted Subsidiary.
 
  Limitation on Liens. The Company shall not, and shall not permit any
Restricted Subsidiary to, directly or indirectly, Incur or permit to exist any
Lien of any nature whatsoever on any of its properties (including Capital
Stock of a Restricted Subsidiary), whether owned at the Issue Date or
thereafter acquired, to secure any Indebtedness that is not Senior
Indebtedness of the Company or such Restricted Subsidiary, other than
Permitted Liens, without effectively providing that the Notes or the
applicable Subsidiary Guaranty shall be secured equally and ratably with (or
prior to) the obligations so secured for so long as such obligations are so
secured.
 
  Limitation on Sale/Leaseback Transactions. The Company shall not, and shall
not permit any Restricted Subsidiary to, enter into any Sale/Leaseback
Transaction with respect to any property unless (i) the Company or such
Restricted Subsidiary would be entitled to (A) Incur Indebtedness in an amount
equal to the Attributable Debt with respect to such Sale/Leaseback Transaction
pursuant to the covenant described under "--Limitation on Indebtedness" and
(B) create a Lien on such property securing such Attributable Debt without
equally and ratably securing the Notes or the applicable Subsidiary Guaranty
pursuant to the covenant described under "--Limitation on Liens", (ii) the net
proceeds received by the Company or any Restricted Subsidiary in connection
with such Sale/Leaseback Transaction are at least equal to the fair value (as
determined by the Board of Directors) of such property and (iii) the Company
applies the proceeds of such transaction in compliance with the covenant
described under "--Limitation on Sales of Assets and Subsidiary Stock".
 
  Future Guarantors. Promptly after the end of the first fiscal year in which
any Restricted Subsidiary (other than the Programs), at the end of such fiscal
year, has total net assets (as set forth on the balance sheet of such
Subsidiary prepared in accordance with GAAP) equal to or greater than the
greater of $2.5 million and one percent (1%) of Adjusted Consolidated Net
Tangible Assets, the Company shall cause such Restricted Subsidiary to issue a
Subsidiary Guaranty for the benefit of the holders of the Notes.
 
  Merger and Consolidation. The Company shall not consolidate with or merge
with or into, or convey, transfer or lease, in one transaction or a series of
transactions, all or substantially all its assets to, any Person, unless: (i)
the resulting, surviving or transferee Person (the "Successor Company") shall
be a Person organized and existing under the laws of the United States of
America, any State thereof or the District of Columbia and the Successor
Company (if not the Company) shall expressly assume, by an indenture
supplemental thereto, executed and delivered to the Trustee, in form
satisfactory to the Trustee, all the obligations of the Company under the
Notes and the Indenture; (ii) immediately after giving effect to such
transaction (and treating any Indebtedness which becomes an obligation of the
Successor Company or any Subsidiary as a result of such transaction as having
been Incurred by such Successor Company or such Subsidiary at the time of such
transaction), no Default shall have occurred and be continuing, (iii)
immediately after giving effect to such transaction, the Successor Company
would be able to Incur an additional $1.00 of Indebtedness pursuant to
paragraph (a) or, if applicable, paragraph (b)(13), of the covenant described
under "--Limitation on Indebtedness", (iv) immediately after giving effect to
such transaction, the Successor Company shall have Adjusted Consolidated Net
Tangible Assets in an amount that is not less than the Adjusted Consolidated
Net Tangible Assets of the Company immediately prior to such transaction; and
(v) the Company shall have delivered to the Trustee an Officers' Certificate
and an Opinion of Counsel, each stating that such consolidation, merger or
transfer and such supplemental indenture (if any) comply with the Indenture;
provided, however, that clauses (iii) and (iv) shall not be applicable to any
such transaction solely between the Company and any Restricted Subsidiary.
 
  The Successor Company shall be the successor to the Company and shall
succeed to, and be substituted for, and may exercise every right and power of,
the Company under the Indenture, but the predecessor Company in
 
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the case of a conveyance, transfer or lease of all or substantially all its
assets shall not be released from the obligation to pay the principal of and
interest on the Notes.
 
  The Company will not permit any Subsidiary Guarantor to consolidate with or
merge with or into, or convey, transfer or lease, in one transaction or series
of transactions, all or substantially all its assets to any Person unless: (i)
the resulting, surviving or transferee Person shall expressly assume by a
guaranty agreement, in a form acceptable to the Trustee, all the obligations
of such Subsidiary Guarantor, if any, under its Subsidiary Guaranty; (ii)
immediately after giving effect to such transaction or transactions on a pro
forma basis (and, treating any Indebtedness which becomes an obligation of the
resulting, surviving or transferee Person as a result of such transaction as
having been issued by such Person at the time of such transaction), no Default
shall have occurred and be continuing; and (iii) the Company delivers to the
Trustee an Officer's Certificate and an Opinion of Counsel, each stating that
such consolidation, merger or transfer and such guaranty agreement, if any,
complies with the Indenture. Notwithstanding the foregoing, upon certain
consolidations, mergers, conveyances, transfers and leases, the Subsidiary
Guarantor and its successor or transferee shall be released from all of such
Subsidiary Guarantor's obligations under its Subsidiary Guaranty as described
in the definition of "Guarantee".
 
  SEC Reports. Notwithstanding that the Company may not at any time be subject
to the reporting requirements of Section 13 or 15(d) of the Exchange Act, the
Company shall file with the SEC and provide the Trustee and Noteholders with
such annual reports and such information, documents and other reports as are
specified in Sections 13 and 15(d) of the Exchange Act (excluding however
information with respect to benefit plans and long-term compensation
arrangements) and applicable to a U.S. corporation subject to such Sections,
such information, documents and other reports to be so filed and provided at
the times specified for the filing of such information, documents and reports
under such Sections.
 
DEFAULTS
 
  An Event of Default is defined in the Indenture as (i) a default in the
payment of interest on the Notes when due, continued for 30 days, (ii) a
default in the payment of principal of any Note when due at its Stated
Maturity, upon optional redemption, upon required repurchase, upon declaration
or otherwise, (iii) the failure by the Company to comply with its obligations
under "--Certain Covenants--Merger and Consolidation" above, (iv) the failure
by the Company to comply for 30 days after notice with any of its obligations
in the covenants described above under "--Certain Covenants", "--Limitation on
Indebtedness", "--Limitation on Restricted Payments", "--Limitation on
Restrictions on Distributions from Restricted Subsidiaries", "--Limitation on
Sales of Assets and Subsidiary Stock" (other than a failure to purchase
Notes), "--Limitation on Affiliate Transactions", "--Limitation on the Sale or
Issuance of Capital Stock of Restricted Subsidiaries", "--Change of Control"
(other than a failure to purchase Notes), "--Limitation on Liens",
"--Limitation on Sale/Leaseback Transactions", "--Future Guarantors" or
"--SEC Reports", (v) the failure by the Company to comply for 60 days after
notice with its other agreements contained in the Indenture, (vi) Indebtedness
of the Company or any Significant Subsidiary (other than Limited Recourse
Indebtedness) is not paid within any applicable grace period after final
maturity or is accelerated by the holders thereof because of a default and the
total amount of such Indebtedness unpaid or accelerated exceeds $10.0 million
(the "cross acceleration provision"), (vii) certain events of bankruptcy,
insolvency or reorganization of the Company or a Significant Subsidiary (the
"bankruptcy provisions"), (viii) any judgment or decree for the payment of money
in excess of $10.0 million is rendered against the Company or a Significant
Subsidiary, remains outstanding for a period of 60 days following such judgment
and is not discharged, waived or stayed within 10 days after notice (the
"judgment default provision") or (ix) a Subsidiary Guaranty ceases to be in full
force and effect (other than in accordance with the terms of such Subsidiary
Guaranty) or a Subsidiary Guarantor denies or disaffirms its obligations under
its Subsidiary Guaranty if such default continues for a period of 10 days after
notice thereof to the Company. However, a default under clauses (iv), (v) and
(viii) will not constitute an Event of Default until the Trustee or the holders
of 25% in principal amount of the outstanding Notes notify the Company of the
default and the Company does not cure such default within the time specified
after receipt of such notice.
 
 
                                      100
<PAGE>
 
  If an Event of Default occurs and is continuing, the Trustee or the holders
of at least 25% in principal amount of the outstanding Notes may declare the
principal of and accrued but unpaid interest on all the Notes to be due and
payable. Upon such a declaration, such principal and interest shall be due and
payable immediately. If an Event of Default relating to certain events of
bankruptcy, insolvency or reorganization of the Company occurs and is
continuing, the principal of and interest on all the Notes will ipso facto
become and be immediately due and payable without any declaration or other act
on the part of the Trustee or any holders of the Notes. Under certain
circumstances, the holders of a majority in principal amount of the
outstanding Notes may rescind any such acceleration with respect to the Notes
and its consequences.
 
  Subject to the provisions of the Indenture relating to the duties of the
Trustee, in case an Event of Default occurs and is continuing, the Trustee
will be under no obligation to exercise any of the rights or powers under the
Indenture at the request or direction of any of the holders of the Notes
unless such holders have offered to the Trustee reasonable indemnity or
security against any loss, liability or expense. Except to enforce the right
to receive payment of principal, premium (if any) or interest when due, no
holder of a Note may pursue any remedy with respect to the Indenture or the
Notes unless (i) such holder has previously given the Trustee notice that an
Event of Default is continuing, (ii) holders of at least 25% in principal
amount of the outstanding Notes have requested the Trustee to pursue the
remedy, (iii) such holders have offered the Trustee reasonable security or
indemnity against any loss, liability or expense, (iv) the Trustee has not
complied with such request within 60 days after the receipt thereof and the
offer of security or indemnity and (v) the holders of a majority in principal
amount of the outstanding Notes have not given the Trustee a direction
inconsistent with such request within such 60-day period. Subject to certain
restrictions, the holders of a majority in principal amount of the outstanding
Notes are given the right to direct the time, method and place of conducting
any proceeding for any remedy available to the Trustee or of exercising any
trust or power conferred on the Trustee. The Trustee, however, may refuse to
follow any direction that conflicts with law or the Indenture or that the
Trustee determines is unduly prejudicial to the rights of any other holder of
a Note or that would involve the Trustee in personal liability.
 
  The Indenture provides that if a Default occurs and is continuing and is
known to the Trustee, the Trustee must mail to each holder of the Notes notice
of the Default within 90 days after it occurs. Except in the case of a Default
in the payment of principal of or interest on any Note, the Trustee may
withhold notice if and so long as a committee of its trust officers determines
that withholding notice is not opposed to the interest of the holders of the
Notes. In addition, the Company is required to deliver to the Trustee, within
120 days after the end of each fiscal year, a certificate indicating whether
the signers thereof know of any Default that occurred during such fiscal year.
The Company also is required to deliver to the Trustee, within 30 days after
the occurrence thereof, written notice of any event which would constitute
certain Defaults, their status and what action the Company is taking or
proposes to take in respect thereto.
 
AMENDMENTS AND WAIVERS
 
  Subject to certain exceptions, the Indenture may be amended with the consent
of the holders of a majority in principal amount of the Notes then outstanding
(including consents obtained in connection with a tender offer or exchange for
the Notes) and any past default or noncompliance with any provisions may also
be waived with the consent of the holders of a majority in principal amount of
the Notes then outstanding. However, without the consent of each holder of an
outstanding Note affected thereby, no amendment may, among other things, (i)
reduce the amount of Notes whose holders must consent to an amendment, (ii)
reduce the rate of or extend the time for payment of interest on any Note,
(iii) reduce the principal of or extend the Stated Maturity of any Note, (iv)
reduce the premium payable upon the redemption of any Note or change the time
at which any Note may be redeemed as described under "--Optional Redemption",
(v) make any Note payable in money other than that stated in the Note, (vi)
impair the right of any holder of the Notes to receive payment of principal of
and interest on such holder's Notes on or after the due dates therefor or to
institute suit for the enforcement of any payment on or with respect to such
holder's Notes, (vii) make any change in the amendment provisions which
require each holder's consent or in the waiver provisions, (viii) make any
change to the subordination provisions of the
 
                                      101
<PAGE>
 
Indenture that would adversely affect the Noteholders or (ix) make any change
in any Subsidiary Guaranty that could adversely affect such holder.
 
  Without notice to or the consent of any holder of the Notes, the Company and
Trustee may amend the Indenture to cure any ambiguity, omission, defect or
inconsistency, to provide for the assumption by a successor corporation of the
obligations of the Company under the Indenture, to provide for uncertificated
Notes in addition to or in place of certificated Notes (provided that the
uncertificated Notes are issued in registered form for purposes of Section
163(f) of the Code, or in a manner such that the uncertificated Notes are
described in Section 163(f)(2)(B) of the Code), to make any change to the
subordination provisions that would limit or terminate the benefits available
to any holder of Senior Indebtedness (or its Representative) to add guarantees
with respect to the Notes, to secure the Notes, to add to the covenants of the
Company for the benefit of the holders of the Notes or to surrender any right
or power conferred upon the Company, to make any change that does not
adversely affect the rights of any holder of the Notes or to comply with any
requirement of the SEC in connection with the qualification of the Indenture
under the Trust Indenture Act. However, no amendment may be made to the
subordination provisions of the Indenture that adversely affects the rights of
any holder of Senior Indebtedness then outstanding unless the holders of such
Senior Indebtedness (or their Representative) consents to such change.
 
  The consent of the holders of the Notes is not necessary under the Indenture
to approve the particular form of any proposed amendment. It is sufficient if
such consent approves the substance of the proposed amendment.
 
  After an amendment under the Indenture becomes effective, the Company is
required to mail to holders of the Notes a notice briefly describing such
amendment. However, the failure to give such notice to all holders of the
Notes, or any defect therein, will not impair or affect the validity of the
amendment.
 
TRANSFER
 
  The Notes will be issued in registered form and will be transferable only
upon the surrender of the Notes being transferred for registration of
transfer. The Company may require payment of a sum sufficient to cover any
tax, assessment or other governmental charge payable in connection with
certain transfers and exchanges.
 
DEFEASANCE
 
  The Company at any time may terminate all its obligations under the Notes
and the Indenture ("legal defeasance"), except for certain obligations,
including those respecting the defeasance trust and obligations to register
the transfer or exchange of the Notes, to replace mutilated, destroyed, lost
or stolen Notes and to maintain a registrar and paying agent in respect of the
Notes. The Company at any time may terminate its obligations under the
covenants described under "--Certain Covenants" (other than the covenant
described under "--Merger and Consolidation"), the operation of the cross
acceleration provision, the bankruptcy provisions with respect to Significant
Subsidiaries and the judgment default provision described under "--Defaults"
above and the limitations contained in clauses (iii) and (iv) under "--Certain
Covenants--Merger and Consolidation" above ("covenant defeasance").
 
  The Company may exercise its legal defeasance option notwithstanding its
prior exercise of its covenant defeasance option. If the Company exercises its
legal defeasance option, payment of the Notes may not be accelerated because
of an Event of Default with respect thereto. If the Company exercises its
covenant defeasance option, payment of the Notes may not be accelerated
because of an Event of Default specified in clause (iv), (vi), (vii) (with
respect only to Significant Subsidiaries) or (viii) under "--Defaults" above
or because of the failure of the Company to comply with clause (iii) or (iv)
under the first of paragraph of "--Certain Covenants--Merger and
Consolidation" above. If the Company exercises its legal defeasance option or
its covenant defeasance option each Subsidiary Guarantor, if any, will be
released from all its obligations with respect to its Subsidiary Guaranty.
 
 
                                      102
<PAGE>
 
  In order to exercise either defeasance option, the Company must irrevocably
deposit in trust (the "defeasance trust") with the Trustee money or U.S.
Government Obligations for the payment of principal and interest on the Notes
to redemption or maturity, as the case may be, and must comply with certain
other conditions, including delivery to the Trustee of an Opinion of Counsel
to the effect that holders of the Notes will not recognize income, gain or
loss for Federal income tax purposes as a result of such deposit and
defeasance and will be subject to Federal income tax on the same amount and in
the same manner and at the same times as would have been the case if such
deposit and defeasance had not occurred (and, in the case of legal defeasance
only, such Opinion of Counsel must be based on a ruling of the Internal
Revenue Service or other change in applicable Federal income tax law).
 
CONCERNING THE TRUSTEE
 
  United States Trust Company of New York is to be the Trustee under the
Indenture and has been appointed by the Company as Registrar and Paying Agent
with regard to the Notes.
 
  The Holders of a majority in principal amount of the outstanding Notes will
have the right to direct the time, method and place of conducting any
proceeding for exercising any remedy available to the Trustee, subject to
certain exceptions. The Indenture provides that if an Event of Default occurs
(and is not cured), the Trustee will be required, in the exercise of its
power, to use the degree of care of a prudent man in the conduct of his own
affairs. Subject to such provisions, the Trustee will be under no obligation
to exercise any of its rights or powers under the Indenture at the request of
any Holder of Notes, unless such Holder shall have offered to the Trustee
security and indemnity satisfactory to it against any loss, liability or
expense and then only to the extent required by the terms of the Indenture.
 
BOOK-ENTRY; DELIVERY AND FORM
 
 
  The Exchange Notes initially will be represented by one permanent global
Exchange Note in definitive, fully registered form without interest coupons
(the "Global Exchange Note") and will be deposited with the Trustee as
custodian for, and registered in the name of, a nominee of DTC.
 
  Ownership of beneficial interests in the Global Exchange Note will be
limited to persons who have accounts with DTC ("participants") or persons who
hold interests through participants. Ownership of beneficial interests in the
Global Exchange Note will be shown on, and the transfer of that ownership will
be effected only through, records maintained by DTC or its nominee (with
respect to interests of participants) and the records of participants (with
respect to interests of persons other than participants).
 
  So long as DTC, or its nominee, is the registered owner or holder of the
Global Exchange Note, DTC or such nominee, as the case may be, will be
considered the sole owner or holder of the Exchange Notes represented by such
Global Exchange Note for all purposes under the Indenture and the Notes. No
beneficial owner of an interest in a Global Exchange Note will be able to
transfer that interest except in accordance with DTC's applicable procedures,
in addition to those provided for under the Indenture and, if applicable,
those of a participant through which the Exchange Note is held.
 
  Payments of the principal of, and interest on, the Global Exchange Note will
be made to DTC or its nominee, as the case may be, as the registered owner
thereof. Neither the Company, the Trustee nor any Paying Agent will have any
responsibility or liability for any aspect of the records relating to or
payments made on account of beneficial ownership interests in the Global
Exchange Note or for maintaining, supervising or reviewing any records
relating to such beneficial ownership interests.
 
  The Company expects that DTC or its nominee, upon receipt of any payment of
principal or interest in respect of the Global Exchange Note, will credit
participants' accounts with payments in amounts proportionate to their
respective beneficial interests in the principal amount of the Global Exchange
Note as shown on the
 
                                      103
<PAGE>
 
records of DTC or its nominee. The Company also expects that payments by
participants to owners of beneficial interests in the Global Exchange Note
held through such participants will be governed by standing instructions and
customary practices, as is now the case with securities held for the accounts
of customers registered in the names of nominees for such customers. Such
payments will be the responsibility of such participants.
 
  Transfers between participants in DTC will be effected in the ordinary way
in accordance with DTC rules and will be settled in same-day funds.
 
  The Company expects that DTC will take any action permitted to be taken by a
holder of Exchange Notes (including the presentation of Exchange Notes for
exchange as described below) only at the direction of one or more participants
to whose account the DTC interests in the Global Exchange Note is credited and
only in respect of such portion of the aggregate principal amount of an
Exchange Note as to which such participant or participants has or have given
such direction. However, if there is an Event of Default under the Notes, DTC
will exchange the applicable Global Exchange Note for Certificated Notes,
which it will distribute to its participants.
 
  The Company understands that: DTC is a limited purpose trust company
organized under the laws of the State of New York, a "banking organization"
within the meaning of New York Banking Law, a member of the Federal Reserve
System, a "clearing corporation" within the meaning of the Uniform Commercial
Code and a "Clearing Agency" registered pursuant to the provisions of Section
17A of the Exchange Act. DTC was created to hold securities for its
participants and facilitate the clearance and settlement of securities
transactions between participants through electronic book-entry changes in
accounts of its participants, thereby eliminating the need for physical
movement of certificates and certain other organizations. Indirect access to
the DTC system is available to others such as banks, brokers, dealers and
trust companies that clear through or maintain a custodial relationship with a
participant, either directly or indirectly ("indirect participants").
 
  Although DTC is expected to follow the foregoing procedures in order to
facilitate transfers of interests in the Global Exchange Note among
participants of DTC, it is under no obligation to perform or continue to
perform such procedures, and such procedures may be discontinued at any time.
Neither the Company nor the Trustee will have any responsibility for the
performance by DTC or its participants or indirect participants of their
respective obligations under the rules and procedures governing their
operations.
 
CERTIFICATED NOTES
 
  The Indenture requires that payments in respect of Notes (including
principal, premium and interest) be made by wire transfer of immediately
available funds to the account specified by the holders thereof or, if no such
account is specified, by mailing a check to each such holder's registered
address.
 
  If DTC is at any time unwilling or unable to continue as a depositary for
the Global Exchange Note and a successor depositary is not appointed by the
Company within 90 days, or if there is an Event of Default under the Notes,
the Company will issue Certificated Notes in exchange for the Global Exchange
Note.
 
GOVERNING LAW
 
  The Indenture provides that it and the Notes will be governed by, and
construed in accordance with, the laws of the State of New York without giving
effect to applicable principles of conflicts of law to the extent that the
application of the law of another jurisdiction would be required thereby.
 
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<PAGE>
 
                CERTAIN U.S. FEDERAL INCOME TAX CONSIDERATIONS
 
  The following is a general discussion of the principal United States federal
income tax consequences of the purchase, ownership and disposition of the
Notes to initial purchasers of Outstanding Notes who are United States Holders
(as defined below) and the principal United States federal income and estate
tax consequences of the purchase, ownership, exchange and disposition of the
Notes to initial purchasers of Outstanding Notes who are Foreign Holders (as
defined below). This discussion was prepared by representatives of the Company
and is based on currently existing provisions of the Code, existing, temporary
and proposed Treasury regulations promulgated thereunder, and administrative
and judicial interpretations thereof, all as in effect or proposed on the date
hereof and all of which are subject to change, possibly with retroactive
effect, or different interpretations. This discussion does not address the tax
consequences to subsequent purchasers of Notes and is limited to purchasers of
Outstanding Notes who hold the Notes as capital assets, within the meaning of
section 1221 of the Code. This discussion also does not address the tax
consequences to Foreign Holders that are subject to United States federal
income tax on a net basis on income realized with respect to a Note because
such income is effectively connected with the conduct of a U.S. trade or
business. Such Foreign Holders are generally taxed in a similar manner to
United States Holders, but certain special rules do apply. Moreover, this
discussion is for general information only and does not address all of the tax
consequences that may be relevant to particular initial purchasers of
Outstanding Notes in light of their personal circumstances or to certain types
of initial purchasers of Outstanding Notes (such as certain financial
institutions, insurance companies, tax-exempt entities, dealers in securities
or persons who have hedged the risk of owning a Note).
 
  PROSPECTIVE PURCHASERS ARE URGED TO CONSULT THEIR OWN TAX ADVISORS AS TO THE
PARTICULAR TAX CONSEQUENCES TO THEM OF THE PURCHASE, OWNERSHIP AND DISPOSITION
OF THE NOTES, INCLUDING THE APPLICABILITY OF ANY FEDERAL TAX LAWS OR ANY
STATE, LOCAL OR FOREIGN TAX LAWS, AND ANY CHANGES (OR PROPOSED CHANGES) IN
APPLICABLE TAX LAWS OR INTERPRETATIONS THEREOF.
 
UNITED STATES FEDERAL INCOME TAXATION OF UNITED STATES HOLDERS
 
  As used herein, the term "United States Holder" means a holder of a Note
that is, for United States federal income tax purposes, (a) a citizen or
resident of the United States, (b) a corporation, partnership or other entity
created or organized in or under the laws of the United States or any
political subdivision thereof or (c) an estate or trust the income of which is
subject to United States federal income taxation regardless of source.
 
  Payment of Interest on Notes. Interest paid or payable on a Note will be
taxable to a United States Holder as ordinary interest income, generally at
the time it is received or accrued, in accordance with such holder's regular
method of accounting for United States federal income tax purposes.
 
  Sale, Exchange or Retirement of the Notes. The exchange of an Outstanding
Note by a United States Holder for an Exchange Note should not constitute a
taxable exchange. For purposes of determining gain or loss on the subsequent
sale or exchange of the Exchange Notes, a Holder's basis in the Exchange Notes
should be the same as the Holder's basis in the Outstanding Notes exchanged
therefor. Holders should be considered to have held the Exchange Notes from
the time of their original acquisition of the Outstanding Notes.
 
  Upon the sale, exchange, redemption, retirement at maturity or other
disposition of a Note, a United States Holder generally will recognize taxable
gain or loss equal to the difference between the sum of cash plus the fair
market value of all other property received on such disposition (except to the
extent such cash or property is attributable to accrued but unpaid interest,
which will be taxable as ordinary income) and such United States Holder's
adjusted tax basis in the Note. A United States Holder's adjusted tax basis in
a Note generally will equal the cost of the Note to such United States Holder,
less any principal payments received by such United States Holder.
 
  Gain or loss recognized on the disposition of a Note generally will be
capital gain or loss and will be long-term capital gain or loss if, at the
time of such disposition, the United States Holder's holding period for the
Note is more than one year.
 
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<PAGE>
 
  Backup Withholding and Information Reporting. Backup withholding and
information reporting requirements may apply to certain payments of principal,
premium, if any, and interest on a Note, and to proceeds of the sale or
redemption of a Note before maturity. The Company, its agent, a broker, the
Trustee or any paying agent, as the case may be, will be required to withhold
from any payment that is subject to backup withholding a tax equal to 31% of
such payment if a United States Holder fails to furnish his taxpayer
identification number (social security or employer identification number),
certify that such number is correct, certify that such holder is not subject
to backup withholding or otherwise comply with the applicable requirements of
the backup withholding rules. Certain United States Holders, including all
corporations, are not subject to backup withholding and information reporting
requirements. Any amounts withheld under the backup withholding rules from a
payment to a United States Holder will be allowed as a credit against such
United States Holder's United States federal income tax and may entitle the
holder to a refund, provided that the required information is furnished to the
Internal Revenue Service ("IRS").
 
UNITED STATES FEDERAL INCOME TAXATION OF FOREIGN HOLDERS
 
  As used herein, the term "Foreign Holder" means a holder of a Note that is,
for United States federal income tax purposes, (a) a nonresident alien
individual, (b) a foreign corporation, (c) a nonresident alien fiduciary of a
foreign estate or trust or (d) a foreign partnership.
 
  Payment of Interest on Notes. In general, payments of interest received by a
Foreign Holder will not be subject to a United States federal withholding tax,
provided that (i)(a) the Foreign Holder does not actually or constructively
own 10% or more of the total combined voting power of all classes of stock of
the Company entitled to vote, (b) the Foreign Holder is not a controlled
foreign corporation that is related to the Company actually or constructively
through stock ownership, (c) the Foreign Holder is not a bank receiving
interest described in Section 881(c)(3)(A) of the Code, and (d) either (I) the
beneficial owner of the Note, under penalties of perjury, provides the Company
or its agent with such beneficial owner's name and address and certifies on
IRS Form W-8 (or a suitable substitute form) that it is not a United States
Holder or (II) a securities clearing organization, bank or other financial
institution that holds customers' securities in the ordinary course of its
trade or business (a "financial institution") holds the Note and provides a
statement to the Company or its agent under penalties of perjury in which it
certifies that such an IRS Form W-8 (or a suitable substitute) has been
received by it from the beneficial owner of the Notes or qualifying
intermediary and furnishes the Company or its agent a copy thereof or (ii) the
Foreign Holder is entitled to the benefits of an income tax treaty under which
interest on the Notes is exempt from United States withholding tax and the
Foreign Holder or such Foreign Holder's agent provides a properly executed IRS
Form 1001 claiming the exemption. Payments of interest not exempt from United
States federal withholding tax as described above will be subject to such
withholding tax at the rate of 30% (subject to reduction under an applicable
income tax treaty).
 
  Sale, Exchange or Retirement of the Notes. The exchange of an Outstanding
Note by a Foreign Holder for an Exchange Note should not constitute a taxable
exchange. For purposes of determining gain or loss on the subsequent sale or
exchange of the Exchange Notes, a Holder's basis in the Exchange Notes should
be the same as the Holder's basis in the Outstanding Notes exchanged therefor.
Holders should be considered to have held the Exchange Notes from the time of
their original acquisition of the Outstanding Notes. Moreover, a Foreign
Holder generally will not be subject to United States federal income tax (and
generally no tax will be withheld) with respect to gain realized on the sale,
exchange, redemption, retirement at maturity or other disposition of a Note
unless the Foreign Holder is an individual who is present in the United States
for a period or periods aggregating 183 or more days in the taxable year of
the disposition and, generally, either has a "tax home" or an "office or other
fixed place of business" in the United States.
 
  Backup Withholding and Information Reporting. Backup withholding and
information reporting requirements do not apply to payments of interest made
by the Company or a paying agent to Foreign Holders if the certification
described above under "--United States Federal Income Taxation of Foreign
Holders--Payment of Interest on Notes" is received, provided that the payor
does not have actual knowledge that the holder is a United States Holder. If
any payments of principal and interest are made to the beneficial owner of a
Note by or
 
                                      106
<PAGE>
 
through the foreign office of a foreign custodian, foreign nominee or other
foreign agent of such beneficial owner, or if the foreign office of a foreign
"broker" (as defined in applicable Treasury regulations) pays the proceeds of
the sale of a Note or a coupon to the seller thereof, backup withholding and
information reporting will not apply. Information reporting requirements (but
not backup withholding) will apply, however, to a payment by a foreign office
of a broker that is a United States person, that derives 50% or more of its
gross income for certain periods from the conduct of a trade or business in
the United States, or that is a "controlled foreign corporation" (generally, a
foreign corporation controlled by certain United States shareholders) with
respect to the United States unless the broker has documentary evidence in its
records that the holder is a Foreign Holder and certain other conditions are
met or the holder otherwise establishes an exemption. Payment by a United
States office of a broker is subject to both backup withholding at a rate of
31% and information reporting unless the holder certifies under penalties of
perjury that it is a Foreign Holder or otherwise establishes an exemption.
 
  The procedures described above for withholding tax on interest payments, and
some of the associated backup withholding and information reporting rules, are
currently the subject of new proposed regulations, which are proposed to be
effective for payments made after December 31, 1997, subject to certain
transition rules. The proposed regulations, if adopted in their current form,
would not substantially change the treatment of Foreign Holders described
above, except that a Form W-8 generally would be required for certification
purposes.
 
  Federal Estate Taxes. Subject to applicable estate tax treaty provisions,
Notes held at the time of death (or Notes transferred before death but subject
to certain retained rights or powers) by an individual who at the time of
death is a Foreign Holder will not be included in such Foreign Holder's gross
estate for United States federal estate tax purposes provided that the
individual does not actually or constructively own 10% or more of the total
combined voting power of all classes of stock of the Company entitled to vote
or hold the Notes in connection with a U.S. trade or business.
 
                             PLAN OF DISTRIBUTION
 
  Each broker-dealer that receives Exchange Notes for its own account pursuant
to the Exchange Offer (a "Participating Broker-Dealer") must acknowledge that
it will deliver a prospectus in connection with any resale of those Exchange
Notes. The Prospectus, as it may be amended or supplemented from time to time,
may be used by a broker-dealer in connection with resales of Exchange Notes
received in exchange for Outstanding Notes where the Outstanding Notes were
acquired by the broker-dealer as a result of market-making activities or other
trading activities. The Company has agreed that for a period of 90 days after
the Expiration Date, it will make this Prospectus, as amended or supplemented,
available to any broker-dealer for use in connection with any resale. In
addition, until               , 1997, all dealers effecting transactions in
the Exchange Notes may be required to deliver a prospectus.
 
  The Company will not receive any proceeds from any sales of the Exchange
Notes by broker-dealers. Exchange Notes received by broker-dealers for their
own account pursuant to the Exchange Offer may be sold from time to time in
one or more transactions in the over-the-counter market, in negotiated
transactions, through the writing of options on the Exchange Notes or a
combination of methods of resale, at market prices prevailing at the time of
resale, at prices related to those prevailing market prices or negotiated
prices. Any such resale may be made directly to the purchaser or to or through
brokers or dealers who may receive compensation in the form of commissions or
concessions from any other broker-dealer or the purchasers of any Exchange
Notes. Any broker-dealer that resells the Exchange Notes that were received by
it for its own account pursuant to the Exchange Offer and any broker or dealer
that participates in a distribution of Exchange Notes may be deemed to be an
"underwriter" within the meaning of the Securities Act, and any profit on any
such resale of Exchange Notes and any commissions or concessions received by
those persons may be deemed to be underwriting compensation under the
Securities Act. The Letter of Transmittal states that by so acknowledging and
by delivering a Prospectus, a broker-dealer will not be deemed to admit that
it is an "underwriter" within the meaning of the Securities Act.
 
 
                                      107
<PAGE>
 
  For a period of 90 days after the Expiration Date, the Company will promptly
send additional copies of this Prospectus and any amendment or supplement to
this Prospectus to any broker-dealer that requests those documents in the
Letter of Transmittal. The Company has agreed to pay certain expenses incident
to the Exchange Offer (including the expenses of one counsel for the Holders
of the Notes), other than commissions or concession of any brokers or dealers,
and will indemnify the holders of the Notes (including any broker-dealers)
against certain liabilities, including liabilities under the Securities Act.
 
  By acceptance of this Exchange Offer, each broker-dealer that receives
Exchange Notes for its own account pursuant to the Exchange Offer agrees that,
on receipt of notice from the Company of the happening of any event which
makes any statement in the Prospectus untrue in any material respect or which
request the making of any changes in the Prospectus in order to make the
statements therein not misleading (which notice the Company agrees to deliver
promptly to the broker-dealer), the broker-dealer will suspend use of the
Prospectus until the Company has amended or supplemented the Prospectus to
correct the misstatement or omission and has furnished copies of the amended
or supplemental Prospectus to the broker-dealer. If the Company shall give any
such notice to suspend the use of the Prospectus, it shall extend the 90-day
period referred to above by the number of days during the period from and
including the date of the giving of the notice to and including when broker-
dealers shall have received copies of the supplemented or amended Prospectus
necessary to permit resales of the Exchange Notes.
 
                                 LEGAL MATTERS
 
  Certain matters with respect to the legality of the Notes are being passed
upon for the Company by Fulbright & Jaworski L.L.P.
 
                                    EXPERTS
 
  In connection with the Contour Transaction, the Company dismissed Ernst &
Young LLP ("E&Y") as its principal accountant, effective February 15, 1996. On
the same date, the Company engaged Deloitte & Touche LLP ("D&T") as its
principal accountant to audit its financial statements. The change in
accountants was approved by the audit committee of the Company's board of
directors, contingent upon the closing of the Contour Transaction. Neither of
E&Y's reports on the Company's financial statements for the years ended
December 31, 1994 and 1993 contained an adverse opinion or disclaimer of
opinion, or was qualified or modified as to uncertainty, audit scope or
accounting principles. During the last two years and the interim period prior
to the change in accountants, (i) the Company had no disagreements with E&Y on
any matter of accounting principles or practices, financial statement
disclosure or auditing scope or procedure, (ii) E&Y did not advise the Company
of any "reportable event" as defined in Regulation S-K under the Securities
Exchange Act of 1934 and (iii) the Company did not consult with D&T on any
accounting, auditing, financial reporting or any other matters.
 
  D&T audited the accounts and financial statements of the Company for the
year ended December 31, 1995 included in this Prospectus, and E&Y audited the
accounts and financial statements of the Company for the years ended December
31, 1994 and 1993 included in this Prospectus. The Company has been informed
by each of D&T and E&Y that neither firm nor any of its respective partners or
employees has any financial interest, direct or indirect, in the Company or in
any of its subsidiaries and that during its association, neither firm nor any
of its respective partners has had any connection with the Company or any of
its subsidiaries in the capacity of promoter, underwriter, voting trustee,
director, officer or other employee.
 
  The consolidated financial statements of Kelley Oil & Gas Corporation as of
December 31, 1995 included in this Prospectus have been audited by Deloitte &
Touche LLP, independent auditors, as stated in their report thereon appearing
herein and are included in reliance upon the report of such firm given upon
their authority as experts in accounting and auditing.
 
                                      108
<PAGE>
 
  The consolidated financial statements of Kelley Oil & Gas Corporation for
the years ended December 31, 1994 and 1993 included in this Prospectus have
been audited by Ernst & Young LLP, independent auditors, as stated in their
report thereon appearing herein and are included in reliance upon the report
of such firm given upon their authority as experts in accounting and auditing.
 
  The consolidated financial statements of Kelley Oil & Gas Partners, Ltd. for
the years ended December 31, 1994 and 1993 included in this Prospectus have
been audited by Ernst & Young LLP, independent auditors, as stated in their
report thereon appearing herein and are included in reliance upon the report
of such firm given upon their authority as experts in accounting and auditing.
 
                        INDEPENDENT PETROLEUM ENGINEERS
 
  The estimated reserve evaluations and related calculations of H. J. Gruy &
Associates, Inc., independent petroleum engineers, have been included herein
in reliance upon the authority of such firm as an expert in petroleum
engineering.
 
                             AVAILABLE INFORMATION
 
  The Company has filed with the Commission a Registration Statement on Form
S-4 (the "Registration Statement") under the Securities Act with respect to
the securities offered by this Prospectus. Certain of the information
contained in the Registration Statement is omitted from this Prospectus, and
reference is hereby made to the Registration Statement and exhibits and
schedules relating thereto for further information with respect to the Company
and the securities offered by this Prospectus. The Company is subject to
certain periodic reporting and other informational requirements of the
Exchange Act, and, in accordance therewith, will file certain reports, proxy
statements and other information with the Commission. Such reports, proxy
statements and other information are available for inspection at, and copies
of these materials may be obtained on payment of the fees prescribed therefor
by the rules and regulations of the Commission from the Commission at its
principal offices located at Judiciary Plaza, 450 Fifth Street, Room 1024,
Washington, D.C. 20549, and at the Regional Offices of the Commission located
at Northwestern Atrium Center, 500 West Madison Street, Suite 1400, Chicago,
Illinois 60661-2511; and at 7 World Trade Center, Suite 1300, New York, New
York 10048. The Commission maintains a World Wide Web site on the Internet at
http://www.sec.gov that contains reports, proxy and information statements and
other information regarding registrants, including the Company, that file
electronically with the Commission.
 
  So long as the Company is subject to the periodic reporting requirements of
the Exchange Act, it is required to furnish the information required to be
filed with the Commission to the Trustee and the holders of the Outstanding
Notes and the Exchange Notes. The Company has agreed that, notwithstanding
that it may not remain subject to the periodic reporting requirements of the
Exchange Act, it will nonetheless continue to furnish information that would
be required by Section 13 of the Exchange Act to be filed by the Company
(excluding information with respect to benefit plans and long-term
compensation arrangements) to the Trustee and the holders of the Outstanding
Notes or Exchange Notes as if it were subject to those periodic reporting
requirements.
 
  In addition, the Company has agreed that for so long as any of the Notes are
outstanding and are "restricted securities" within the meaning of Rule
144(a)(3) under the Securities Act, it will make available to any prospective
purchaser of the Notes or beneficial owner of the Notes in connection with any
sale thereof the information required by Rule 144A(d)(4) under the Securities
Act until such time as the Company has either exchanged the Outstanding Notes
for the Exchange Notes or until such time as the holders thereof have disposed
of the Outstanding Notes pursuant to an effective registration statement filed
by the Company.
 
                                      109
<PAGE>
 
                      INCORPORATION OF CERTAIN DOCUMENTS
 
  All documents filed by the Company pursuant to the Exchange Act, after the
date of this Prospectus and before the termination of the Registration
Statement of which this Prospectus is a part with respect to registration of
the Exchange Notes, shall be deemed to be incorporated by reference in this
Prospectus and be a part hereof from the date of filing of such documents. Any
statement contained in a document incorporated or deemed to be incorporated by
reference in this Prospectus shall be deemed to be modified or superseded for
purposes of this Prospectus to the extent that a statement contained in this
Prospectus, or in any other subsequently filed document that also is or is
deemed to be incorporated by reference, modifies or replaces such statement.
 
  The Company undertakes to provide without charge to each person, including
any beneficial owner, to whom a copy of this Prospectus has been delivered, on
written or oral request of that person, a copy of any or all of the documents
incorporated by reference herein, other than exhibits to those documents,
unless those exhibits are specifically incorporated by reference into the
information that this Prospectus incorporates. Written or oral requests for
copies of these materials should be directed to: Kelley Oil & Gas Corporation,
601 Jefferson, Suite 1100 Houston, Texas 77002, Attention: Investor Relations,
telephone (713) 652-5200.
 
                                      110
<PAGE>
 
                                   GLOSSARY
 
  BBL. One stock tank barrel, or 42 U.S. Gallons liquid volume, used herein in
reference to crude oil or other liquid hydrocarbons.
 
  BCF. One billion cubic feet of natural gas.
 
  BCFE. One billion cubic feet of natural gas equivalent (see Mcfe for
equivalency).
 
  "BEHIND PIPE" Hydrocarbons in a potentially producing horizon penetrated by
a wellbore, the production of which has been postponed pending the production
of hydrocarbons from another formation penetrated by the wellbore. These
hydrocarbons are classified as proved but non-producing reserves.
 
  3-D SEISMIC. (Three-Dimensional Seismic) Seismic reflections from the
subsurface used to map strata in three dimensions.
 
  "DEVELOPMENT COSTS" The costs incurred in preparing proved reserves for
production, i.e., costs incurred to obtain access to proved reserves and to
provide facilities for extracting, treating, gathering, and storing oil and
gas, but not including exploration costs.
 
  "DEVELOPMENT WELL" A well drilled within the proved area of an oil or
natural gas reservoir to the depth of a stratigraphic horizon known to be
productive.
 
  "ESTIMATED FUTURE NET REVENUES" are the estimated net revenues (cash flows)
expected to be derived upon production and sale from proved oil and gas
reserves at a date indicated. Estimated future net revenues are computed after
giving effect to estimated future development and production costs at a date
indicated and assuming the continuation of existing economic conditions. The
calculation does not take into account the effect of various cash outlays,
including general and administrative costs and interest expense, and does not
give effect to estimated future income taxes.
 
  "EXPLORATION COSTS" Costs incurred in exploring property. Exploration
involves identifying areas that may warrant examination and examining specific
areas, including drilling exploratory wells.
 
  "GROSS ACRES" The total number of acres in which a working interest is
owned.
 
  "GROSS WELLS" The total number of wells in which a working interest is
owned.
 
  "LEASE OPERATING EXPENSES" The expenses of lifting oil and gas from a
producing formation to the surface, and the transportation and marketing
thereof, constituting part of the current operating expenses of a working
interest, and also including labor, superintendence, supplies, repairs,
maintenance, allocated overhead costs, ad valorem taxes and other expenses
incidental to production, but not including severance taxes or capital costs.
 
  MBBLS. One thousand barrels of crude oil or other liquid hydrocarbons.
 
  MCF. One thousand cubic feet of natural gas.
 
  MCFE. One thousand cubic feet of natural gas equivalent (converting one
barrel of oil to six Mcf of natural gas based on commonly accepted rough
equivalency of energy content).
 
  MMBBLS. One million barrels of crude oil or other liquid hydrocarbons.
 
  MMBTU. One million British Thermal Units.
 
  MMCF. One million cubic feet of natural gas.
 
  MMCFE. One million cubic feet of natural gas equivalent (see Mcfe for
equivalency).
 
                                      111
<PAGE>
 
  "NET ACRES" The sum of acres determined by adding the products of gross
acres in which there is an interest multiplied by the fractional working
interests of Kelley therein.
 
  "NET WELLS" The sum of the fractional working interests owned by Kelley in
gross wells.
 
  NYMEX. New York Mercantile Exchange.
 
  "PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES" An estimate of the present
value of the estimated future net revenues is calculated by discounting
estimated future net revenues at an annual rate of 10%, in accordance with SEC
practice, to determine their "present value". The present value is shown to
indicate the effect of time on the value of the revenue stream and should not
be construed as being the fair market value of the properties. Estimates of
future net cash revenues are made using oil and natural gas prices and costs
at the date indicated and held constant for the life of the reserves.
 
  "PRODUCING WELL" or "PRODUCTIVE WELL" A well that is producing oil or
natural gas or that is capable of producing commercial quantities without
further capital expenditure.
 
  "PRODUCTION EXPENSES" Lease operating expenses plus severance taxes.
 
  "PROVED DEVELOPED RESERVES" Proved developed reserves are those quantities
of crude oil, natural gas and natural gas liquids that, upon analysis of
geological and engineering data, that can be expected with reasonable
certainty to be recoverable in the future from known oil and natural gas
reservoirs under existing economic and operating conditions. This
classification includes those: (a) which are expected to be recovered from
currently open and producing zones under continuation of existing equipment
and operating methods (proved developed producing reserves); and (b) which
consist of (i) reserves from wells that have been completed and tested but are
not yet producing due to lack of market or minor completion problems that
reasonably can be expected to be corrected, and (ii) reserves currently behind
pipe in existing wells which reasonably can be expected to be productive due
to both the well log characteristics and analogous production in the immediate
vicinity of the well (proved developed nonproducing reserves).
 
  "PROVED RESERVES" Proved reserves are those estimated quantities of crude
oil, natural gas and other hydrocarbon liquids which, by analysis of
geological and engineering data, can be estimated with reasonable certainty to
be commercially recoverable in future years from known reservoirs and under
current economic conditions, operating methods and government regulations.
 
  "PROVED UNDEVELOPED RESERVES" Proved undeveloped reserves are reserves that
are expected to be recovered from (a) new wells on undrilled acreage, (b)
deepening existing wells to a different reservoir or (c) where a relatively
large expenditure is required to (i) recomplete an existing well or (ii)
install production or transportation facilities for primary or improved
recovery projects.
 
  "RESERVES TO PRODUCTION RATIO" Calculated by dividing the total proved
reserves as of a specific date by production for the twelve-month period
immediately preceding such date. This term is sometimes referred to as
"average reserve life" (in years) or "estimated reserve life" (in years) by
industry participants or followers.
 
  "WORKING INTEREST" The interest in an oil and gas property (normally a
leasehold interest) that gives the owner the right to drill, produce and
conduct oil and gas operations on the property and to a share of production,
subject to all royalties, overriding royalties and other burdens and to all
costs of exploration, development and operations and all risks in connection
therewith.
 
                                      112
<PAGE>
 
                   INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
 
<TABLE>
<CAPTION>
                                                                           PAGE
                                                                           ----
<S>                                                                        <C>
KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES:
Independent Auditors' Reports............................................   F-2
Consolidated Balance Sheets at December 31, 1994 and 1995 and unaudited
 at September 30, 1996...................................................   F-4
Consolidated Statements of Loss for the years ended December 31, 1993,
 1994 and 1995 and unaudited for the nine months ended September 30, 1995
 and 1996................................................................   F-5
Consolidated Statements of Cash Flows for the years ended December 31,
 1993, 1994 and 1995 and unaudited for the nine months ended
 September 30, 1995 and 1996.............................................   F-6
Consolidated Statements of Changes in Stockholders' Equity (Deficit) for
 the years ended December 31, 1993, 1994 and 1995 and unaudited for the
 nine months ended September 30, 1996....................................   F-7
Notes to Consolidated Financial Statements...............................   F-8
Unaudited Pro Forma Statement of Loss for the year ended December 31,
 1995 ...................................................................  F-30
Notes to Unaudited Pro Forma Financial Statement of Loss.................  F-31
KELLEY OIL & GAS PARTNERS, LTD.:
Independent Auditors' Report.............................................  F-32
Consolidated Balance Sheets at December 31, 1993 and 1994................  F-33
Consolidated Statements of Loss for the years ended December 31, 1993 and
 1994 and unaudited for the period from January 1, 1995 through
 February 7, 1995........................................................  F-34
Consolidated Statements of Cash Flows for the years ended December 31,
 1993 and 1994 and unaudited for the period from January 1, 1995 through
 February 7, 1995........................................................  F-35
Consolidated Statements of Changes in Partners' Equity for the years
 ended December 31, 1993 and 1994 and unaudited for the period from
 January 1, 1995 through February 7, 1995................................  F-36
Notes to Consolidated and Interim Financial Statements...................  F-37
</TABLE>
 
 
                                      F-1
<PAGE>
 
                         INDEPENDENT AUDITORS' REPORT
 
To the Board of Directors and Stockholders of Kelley Oil & Gas Corporation
 
  We have audited the accompanying consolidated balance sheet of Kelley Oil &
Gas Corporation and subsidiaries as of December 31, 1995, and the related
consolidated statements of loss, cash flows, and stockholders' equity
(deficit) for the year then ended. These financial statements are the
responsibility of the Company's management. Our responsibility is to express
an opinion on these financial statements based on our audit.
 
  We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audit provides a reasonable basis
for our opinion.
 
  In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of Kelley Oil & Gas Corporation
and subsidiaries at December 31, 1995, and the results of their operations and
their cash flows for the year then ended, in conformity with generally
accepted accounting principles.
 
  As discussed in Note 1 to the consolidated financial statements, in 1995 the
Company changed its method of accounting for the impairment of long-lived
assets to conform with Statement of Financial Accounting Standards No. 121.
 
DELOITTE & TOUCHE LLP
 
Houston, Texas
March 28, 1996
 
 
                                      F-2
<PAGE>
 
                         INDEPENDENT AUDITORS' REPORT
 
To the Board of Directors and Stockholders of Kelley Oil & Gas Corporation
 
  We have audited the accompanying consolidated balance sheet of Kelley Oil &
Gas Corporation and Subsidiaries (the "Company") as of December 31, 1994, and
the related consolidated statements of loss, stockholders' equity, and cash
flows for each of the two years in the period ended December 31, 1994. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
 
  We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the 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, the consolidated financial statements referred to above
present fairly, in all material respects, the consolidated financial position
of Kelley Oil & Gas Corporation and Subsidiaries at December 31, 1994, and the
consolidated results of their operations and their cash flows for each of the
two years in the period ended December 31, 1994, in conformity with generally
accepted accounting principles.
 
  As discussed in Note 1 to the financial statements, in 1994 the Company
changed its method of accounting for oil and gas production activities.
 
                                          Ernst & Young LLP
 
Houston, Texas
March 6, 1995
 
 
                                      F-3
<PAGE>
 
                 KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
 
                          CONSOLIDATED BALANCE SHEETS
 
                                 (IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                                 DECEMBER 31,
                                               ------------------  SEPTEMBER 30,
                                                 1994      1995        1996
                                               --------  --------  -------------
                                                                    (UNAUDITED)
<S>                                            <C>       <C>       <C>
ASSETS:
  Cash and cash equivalents..................  $  9,268     6,352       2,531
  Accounts receivable........................    11,059    13,753     16, 207
  Accounts receivable--drilling programs.....     7,330     2,035       2,413
  Prepaid expenses and other current assets..       222       557       1,694
                                               --------  --------    --------
   Total current assets......................    27,879    22,697      22,845
                                               --------  --------    --------
  Oil and gas properties, successful efforts
   method:
   Unproved properties, net..................     1,430    13,050      13,342
   Properties subject to amortization........   129,883   287,970     330,091
  Pipelines and other transportation assets,
   at cost...................................     2,652     4,723       4,689
  Furniture, fixtures and equipment..........     1,665     1,233       1,468
                                               --------  --------    --------
                                                135,630   306,976     349,590
  Less: Accumulated depreciation, depletion
   and amortization..........................   (60,718) (178,334)   (194,088)
                                               --------  --------    --------
   Total property and equipment..............    74,912   128,642     155,502
                                               --------  --------    --------
  Other non-current assets (net of
   accumulated amortization).................     3,722         3       1,074
                                               --------  --------    --------
  TOTAL ASSETS...............................  $106,513   151,342     179,421
                                               ========  ========    ========
LIABILITIES:
  Accounts payable and accrued expenses......  $  5,696    19,500      28,695
  Accounts payable--drilling programs........    15,924    12,430      11,212
  Current maturities of long-term bank debt..     2,471        --          --
                                               --------  --------    --------
   Total current liabilities.................    24,091    31,930      39,907
                                               --------  --------    --------
  Long-term bank debt........................    26,480    22,000       7,000
  Senior notes...............................        --    95,926      96,796
  Convertible subordinated debentures........     5,097    21,694      22,605
  Convertible subordinated notes.............     5,665    25,360      26,948
                                               --------  --------    --------
   TOTAL LIABILITIES.........................    61,333   196,910     193,256
                                               --------  --------    --------
STOCKHOLDERS' EQUITY (DEFICIT):
  Preferred stock, $1.50 par value, 10,000,
   20,000 and 20,000 shares authorized at
   December 31, 1994 and 1995 and September
   30, 1996, respectively; 5,163, 4,304 and
   1,746 shares issued and outstanding at
   December 31, 1994 and 1995 and September
   30, 1996, respectively (liquidation value
   $53,750, $66,532 and $47,074,
   respectively).............................     7,743     6,456       2,618
  Common stock, $.01 par value, 35,000,
   100,000 and 200,000 shares authorized at
   December 31, 1994 and 1995 and September
   30, 1996, respectively; 17,685, 44,041 and
   98,288 shares issued and outstanding at
   December 31, 1994 and 1995 and September
   30, 1996, respectively....................       177       440         983
  Additional paid-in capital.................    98,647   225,804     273,088
  Retained deficit...........................   (60,366) (278,268)   (290,524)
                                               --------  --------    --------
                                                 46,201   (45,568)    (13,835)
  Less: deferred employee compensation.......    (1,021)       --          --
                                               --------  --------    --------
   TOTAL STOCKHOLDERS' EQUITY (DEFICIT)......    45,180   (45,568)    (13,835)
                                               --------  --------    --------
  TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY
   (DEFICIT).................................  $106,513   151,342     179,421
                                               ========  ========    ========
</TABLE>
 
                See Notes to Consolidated Financial Statements.
 
                                      F-4
<PAGE>
 
                 KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
 
                        CONSOLIDATED STATEMENTS OF LOSS
 
                     (IN THOUSANDS, EXCEPT PER SHARE DATA)
 
<TABLE>
<CAPTION>
                                                          NINE MONTHS ENDED
                            YEAR ENDED DECEMBER 31,         SEPTEMBER 30,
                           ---------------------------  ----------------------
                             1993     1994      1995       1995        1996
                           --------  -------  --------  ----------- ----------
                                                        (UNAUDITED) (UNAUDITED)
<S>                        <C>       <C>      <C>       <C>         <C>
Oil and gas revenues.....  $ 19,711   15,487    36,042     26,284     40,201
Gas marketing revenues,
 net.....................     1,353    1,335       956        677      1,078
Gain on sale of oil and
 gas properties..........        --       --       777        777         --
Interest and other
 income..................     1,506    1,416       986        727        938
                           --------  -------  --------    -------    -------
  Total revenues.........    22,570   18,238    38,761     28,465     42,217
                           --------  -------  --------    -------    -------
Production expenses......     3,993    3,760    10,835      7,739      7,638
Exploration costs........    14,226    7,404    23,387     10,523      4,216
General and
 administrative
 expenses................     4,079    5,172     7,030      4,346      6,950
Interest expense and
 other debt expenses.....     6,638    4,571    21,956     15,137     18,376
Restructuring expense....        --    1,814     1,115         --      2,000
Depreciation, depletion
 and amortization........    18,857   20,474    35,591     23,704     15,293
Impairment of oil and gas
 properties..............        --       --   150,138         --         --
                           --------  -------  --------    -------    -------
  Total expenses.........    47,793   43,195   250,052    61, 449     54,473
                           --------  -------  --------    -------    -------
Loss before income
 taxes...................   (25,223) (24,957) (211,291)   (32,984)   (12,256)
Income taxes.............        --       --        --         --         --
                           --------  -------  --------    -------    -------
Net loss.................   (25,223) (24,957) (211,291)   (32,984)   (12,256)
Less: cumulative
 preferred stock
 dividends...............       894    2,905     6,607     (4,867)        --
                           --------  -------  --------    -------    -------
NET LOSS APPLICABLE TO
 COMMON STOCK............  $(26,117) (27,862) (217,898)   (37,851)   (12,256)
                           ========  =======  ========    =======    =======
Loss per share:
  Primary and assuming
   full dilution:
    Net loss.............  $  (1.63)   (1.58)    (5.31)      (.94)      (.14)
                           ========  =======  ========    =======    =======
Average common and common
 equivalent shares
 outstanding:
  Primary and assuming
   full dilution.........    15,967   17,653    41,032     40,141     87,368
</TABLE>
 
                See Notes to Consolidated Financial Statements.
 
 
                                      F-5
<PAGE>
 
                 KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
 
                     CONSOLIDATED STATEMENTS OF CASH FLOWS
 
                                 (IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                                            NINE MONTHS ENDED
                             YEAR ENDED DECEMBER 31,          SEPTEMBER 30,
                            ---------------------------  -----------------------
                              1993     1994      1995       1995        1996
                            --------  -------  --------  ----------- -----------
                                                         (UNAUDITED) (UNAUDITED)
<S>                         <C>       <C>      <C>       <C>         <C>
OPERATING ACTIVITIES:
Net loss..................  $(25,223) (24,957) (211,291)   (32,984)    (12,256)
Adjustments to reconcile
 net loss to net cash
 provided by (used in)
 operating activities:
  Depreciation, depletion
   and amortization.......    18,857   20,474    35,591     23,704      15,293
  Impairment of oil and
   gas properties.........        --       --   150,138
  Gain on sale of oil and
   gas properties.........        --       --      (777)      (777)        (77)
  Dry hole costs..........    11,773    4,751    18,152
  Amortization of
   debenture and note
   costs..................        91       29     1,019
  Debenture conversion
   costs..................     2,490    1,449        --
  Accretion of debt
   discount...............        --       --     1,866
  Accretion of note
   discount...............        75      111       717
  Restructuring expense...        --       --        --
  Changes in operating
   assets and liabilities:
  Decrease (increase) in
   accounts receivable....    10,502   (1,896)    9,419     11,979      (3,115)
  Decrease (increase) in
   prepaid expenses and
   other current assets...       282      116        38         41      (1,137)
  Decrease (increase) in
   other non-current
   assets.................     1,723   (2,274)    3,075      1,971      (1,629)
  Increase (decrease) in
   accounts payable and
   accrued expenses.......    (1,132)  (2,128)  (14,988)   (13,365)      4,794
                            --------  -------  --------   --------     -------
Net cash provided by (used
 in) operating
 activities...............    19,438   (4,325)   (7,041)    (1,361)      8,062
                            --------  -------  --------   --------     -------
INVESTING ACTIVITIES:
Investment in property and
 equipment................   (38,602) (42,323)  (47,005)   (32,295)    (41,402)
Cash received in
 consolidation............        --       --     1,596      1,596          --
Proceeds from sale of oil
 and gas properties.......        --       --     6,836      6,807          --
Proceeds from sale of
 equipment................        82      265       584        403         530
                            --------  -------  --------   --------     -------
Net cash used in investing
 activities...............   (38,520) (42,058)  (37,989)  (23,489)     (40,872)
                            --------  -------  --------   --------     -------
FINANCING ACTIVITIES:
Proceeds from long term
 borrowings...............    21,785   34,302    37,100     15,100      29,000
Principal payments on
 long-term borrowings.....    (5,462) (19,000) (100,000)  (100,000)    (44,000)
Proceeds from sale of
 senior notes.............        --       --    99,629     99,629          --
Proceeds from sale of
 preferred stock..........        --   32,503        --         --          --
Proceeds from sale of
 common stock.............       297      123    16,319     16,319      48,052
Dividends paid on
 preferred stock..........      (894)  (2,905)   (6,607)    (4,867)         --
Note offering costs.......        --       --    (4,327)    (4,289)         --
Syndication costs charged
 to equity................        --       --        --         (5)     (4,063)
Debenture conversion
 costs....................      (356)     (79)       --         --          --
                            --------  -------  --------   --------     -------
Net cash provided by
 financing activities.....    15,370   44,944    42,114     21,887      28,989
                            --------  -------  --------   --------     -------
Increase (decrease) in
 cash and cash
 equivalents..............    (3,712)  (1,439)   (2,916)    (2,963)     (3,821)
Cash and cash equivalents,
 beginning of period......    14,419   10,707     9,268      9,268       6,352
                            --------  -------  --------   --------     -------
Cash and cash equivalents,
 end of period............  $ 10,707    9,268     6,352      6,305       2,531
                            ========  =======  ========   ========     =======
</TABLE>
 
                See Notes to Consolidated Financial Statements.
 
                                      F-6
<PAGE>
 
                 KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
 
      CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (DEFICIT)
 
                                 (IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                                            ADDITIONAL RETAINED
                                           PREFERRED COMMON  PAID IN   EARNINGS
                                             STOCK   STOCK   CAPITAL   (DEFICIT)
                                           --------- ------ ---------- ---------
<S>                                        <C>       <C>    <C>        <C>
Stockholders' equity at January 1, 1993..   $ 5,055   147     30,296     (6,387)
Issuance of 2,821 shares of common stock
 upon conversion of debentures...........        --    28     27,046         --
Issuance of 88 shares of common stock....        --     1        296         --
Preferred stock cash dividends...........        --    --         --       (894)
Net loss.................................        --    --         --    (25,223)
                                            -------   ---    -------   --------
  BALANCE AT DECEMBER 31, 1993...........     5,055   176     57,638    (32,504)
                                            -------   ---    -------   --------
Issuance of 1,380 shares of preferred
 stock, $1.50 par value..................     2,070    --     30,433         --
Issuance of 413 shares of preferred stock
 in exchange for debentures, $1.50 par
 value...................................       618    --     10,454         --
Issuance of 66 shares of common stock....        --     1        122         --
Preferred stock cash dividends...........        --    --         --     (2,905)
Net loss.................................        --    --         --    (24,957)
                                            -------   ---    -------   --------
  BALANCE AT DECEMBER 31, 1994...........     7,743   177     98,647    (60,366)
                                            -------   ---    -------   --------
Additional paid in capital from issuance
 of preferred and common stock in
 consolidation...........................        --    --    108,632         --
Issuance of 650 shares of preferred
 stock, $1.50 par value, in
 consolidation...........................       975    --         --         --
Issuance of 20,622 shares of common stock
 in consolidation........................        --   206         --         --
Issuance of 4,000 shares of common stock
 in private placement....................        --    40     15,960         --
Conversion of 1,508 shares of preferred
 stock to 1,508 shares of common stock...    (2,262)   15      2,247         --
Issuance of 225 shares of common stock...        --     2        318         --
Syndication costs........................        --    --         --         (4)
Preferred stock cash 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 to 4,355 shares of common stock...    (1,045)   44      1,002         --
Conversion of 1,862 shares of preferred
 stock to 1,862 shares of common stock...    (2,793)   19      2,774         --
Issuance of 30 shares of common stock....        --    --         52         --
Syndication costs........................        --    --     (4,064)        --
Net loss.................................        --    --         --    (12,256)
                                            -------   ---    -------   --------
  BALANCE AT SEPTEMBER 30, 1996
   (unaudited)...........................   $ 2,618   983    273,088    290,524
                                            =======   ===    =======   ========
</TABLE>
 
                See Notes to Consolidated Financial Statements.
 
                                      F-7
<PAGE>
 
                 KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
 
                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
NOTE 1--SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
  Organization. Kelley Oil & Gas Corporation (the "Company" or "KOGC") 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 of oil and gas properties and
the purchase, sale and transportation of natural gas. In March 1996, Kelley
Partners was merged into the Company (the "Partnership Merger"). See Note 2--
Affiliated Programs and Managed Properties.
 
  Accounting Treatment of the Consolidation. In the Consolidation, each
outstanding unit of limited partner interest ("Units") in Kelley Partners
owned by investors other than Kelley Oil and its subsidiaries ("Public
Unitholders") was converted into 1.2188 shares of KOGC's common stock ("Common
Stock") or, at the election of each Public Unitholder, .609 of a share of
Common Stock and .127 of a share of KOGC's $2.625 convertible exchangeable
preferred stock ("Preferred Stock"). Stockholders of Kelley Oil received
equivalent securities of the Company on a one for one basis. Kelley Oil's
19.9% ownership interest in Kelley Partners was not converted into the
Company's Common or Preferred Stock, since that ownership interest was
reflected in the valuation of Kelley Oil and the consideration allocated to
its stockholders. At the time of the Consolidation, the KOGC capital stock
received by Kelley Oil's stockholders represented a majority of the total
voting power of the combined capital stock issued by the Company in the
Consolidation. Accordingly, the Consolidation has been treated as a purchase
by the Company of the Public Unitholders' interests in Kelley Partners. As a
result of the purchase accounting treatment of the Consolidation, the
Company's consolidated financial statements through December 31, 1994 reflect
only Kelley Oil's historical results, and its financial statements for 1995
reflect Kelley Oil's historical results through the date of the Consolidation,
with results of combined operations recorded thereafter.
 
  Principles of Consolidation. The consolidated financial statements include
the accounts of the Company and its corporate subsidiaries, all of which are
wholly owned, and KOGC's proportionate interests in Kelley Partners, its
operating partnership, Kelley Operating Company, Ltd. ("Kelley Operating"),
and development drilling programs sponsored by Kelley Oil to conduct drilling
operations on properties of Kelley Operating ("DDPs"). All significant
intercompany accounts and transactions have been eliminated in consolidation.
 
  Revenue Recognition. 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 in production operations is not significantly
different from the Company's share of production. Revenues from the purchase,
sale and transportation of natural gas are recognized upon completion of the
sale and when transported volumes are delivered. In addition, gas marketing
revenues and cost of gas sold have been presented on a net basis for the
periods presented and are reflected in "Gas marketing revenues, net" on the
Consolidated Statements of Loss.
 
  Oil and Gas Properties. The Company's interests in its oil and gas
properties are held directly by the Company, Kelley Operating, Kelley Oil and
Petrofunds, Inc. (a subsidiary of the Company). All of these properties are
located in the United States.
 
  Under the successful efforts method adopted by KOGC, the costs of successful
wells, development dry holes and productive leases are capitalized and
amortized on a unit-of-production basis over the life of the related reserves.
Cost centers for amortization purposes are determined on a field-by-field
basis. Estimated future abandonment and site restoration costs, net of
anticipated salvage values, are taken into account in depreciation, depletion
and amortization. Exploratory drilling costs are initially capitalized pending
determination of proved
 
                                      F-8
<PAGE>
 
                 KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

reserves but are charged to expense if no proved reserves are found. Other
exploration costs, including geological and geophysical expenses, leasehold
expiration costs and delay rentals, are expensed as incurred. Unproved
properties are periodically assessed for impairment in value, with any
impairment charged to expense.
 
  Property Impairment under FAS 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 ("FAS 121"). Under FAS 121, certain assets are
required to be reviewed periodically for impairment whenever circumstances
indicate their carrying amount exceeds their fair value and may not be
recoverable. As a result of its continuing operating losses and a decline in
its proved reserves at January 1, 1996 from year-earlier pro forma levels, the
Company performed an assessment of the carrying value of its oil and gas
properties indicating an impairment should be recognized as of year end. Under
this analysis, the fair value for KOGC's proved oil and gas properties was
estimated on a depletable unit basis using escalated pricing and present value
discount factors reflecting risk assessments. The fair value of 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 FAS
121 aggregating $83.4 million and $66.7 million, respectively, at December 31,
1995.
 
  Pipelines and Other Transportation Assets. 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. Furniture, fixtures and equipment are
recorded at cost and depreciated using the straight-line method over the
estimated useful life of five years. Maintenance and repairs are charged to
expense.
 
  Restructuring. On December 29, 1994, Kelley Oil implemented a restructuring
focused on staff reductions of approximately 25% intended to streamline
management and administrative functions and reduce general and administrative
expenses. An additional management realignment was implemented in the fourth
quarter of 1995. Non-recurring charges of $1.8 million and $1.1 million were
taken in the fourth quarters of 1994 and 1995, respectively, to account for
these measures. In the second quarter of 1996, the Company incurred a $2.0
million (unaudited) restructuring charge, associated with management
realignment and termination settlements. Of this amount $.3 million
(unaudited) was paid in the second quarter with the balance of $1.7 million
(unaudited) included in accounts payable and accrued expenses on the balance
sheet. Management anticipates an additional restructuring charge will be
incurred by the end of 1996.
 
  Loss per Share. Primary loss per share reflects net loss less preferred
stock dividends divided by the average number of common shares and equivalents
outstanding during the respective years. Common shares issuable under stock
options and upon conversion of convertible subordinated debentures and
convertible preferred stock are added to average common shares and equivalents
outstanding when dilutive.
 
  Income Taxes. Under the Statement of Financial Accounting Standards No. 109
("SFAS 109"), the tax effect of each item in the consolidated statements of
loss is recognized in the current period regardless of when the tax is paid.
Taxes on amounts that affect financial and taxable income in different periods
are reported as deferred income taxes. These temporary differences relate
primarily to (i) intangible drilling and development costs associated with oil
and gas properties capitalized and amortized based upon units of production
for financial reporting purposes and expensed as incurred for tax reporting
purposes and (ii) differences in financial reporting provisions for
depreciation and amortization and that of income tax reporting. See Note 6--
Income Taxes.
 
  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. Included in cash and cash equivalents at December 31,
1994 was a $.2 million certificate of deposit pledged to support Kelley Oil's
guaranty of ESOP borrowings. See Note 3--Long Term Debt.
 
                                      F-9
<PAGE>
 
                 KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
  Financial Instruments. The Company's financial instruments consist of cash
and cash equivalents, receivables, payables and debt. As of December 31, 1995,
the estimated fair value of the Company's debt approximated its carrying
value. The estimated fair values at December 31, 1995 were determined using
the Black-Scholes pricing model based on quoted market prices and the
borrowing rates available for debt with similar terms and maturities.
 
  Derivative Financial Instruments. From time to time, the Company has entered
into transactions in derivative financial instruments covering future natural
gas production principally as a hedge against natural gas price declines.
Realized and unrealized gains and losses are recorded in other assets or
liabilities until the underlying natural gas is produced and sold, at which
time those gains and losses are included in oil and gas revenues. See Note
12--Hedging Activities.
 
  Other Non-Current Assets. Other non-current assets consist of debt issue
costs, goodwill and other intangible assets. Goodwill is amortized on a
straight-line basis over 10 years for the Company and 15 years for Concorde
Gas, Inc., an indirect wholly owned subsidiary of the Company ("CGI"). In
1995, the Company recognized impairments of goodwill aggregating $.7 million
associated with acquisition costs for CGI and Wincan, Inc., an indirect wholly
owned subsidiary of the Company. In addition, the Company wrote off prepaid
financing costs of $1.7 million in connection with a related bank debt
refinancing. Accumulated amortization at December 31, 1993 and 1994 was $.9
million and $1.2 million, respectively.
 
  Concentration of Credit Risk. Substantially all of KOGC's receivables are
due from a limited number of natural gas transmission companies and other gas
purchasers. To date, this concentration has not had a material adverse effect
on the consolidated financial condition of the Company.
 
  Stock Based Compensation. In October 1995, the Financial Accounting
Standards Board issued Statement of Financial Accounting Standard No. 123,
Accounting for Stock Based Compensation ("FAS 123"), effective for the Company
on January 1, 1996. FAS 123 permits, but does not require, a fair value based
method of accounting for employee stock option plans, resulting in
compensation expense being recognized in the results of operations when stock
options are granted. The Company plans to continue the use of its current
intrinsic value based method of accounting for stock option plans where no
compensation expense is recognized. However, as required by FAS 123, the
Company will provide pro forma disclosure of net income and earnings per share
in the notes to the consolidated financial statements as if the fair value
based method of accounting had been applied.
 
  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 1993 and 1994
have been reclassified to conform to the 1995 presentation.
 
  Interim Presentation (Unaudited). The accompanying consolidated financial
statements of Kelley Oil & Gas Corporation (the "Company" or "KOGC") have been
prepared by the Company in accordance with generally accepted accounting
principles and reflect all adjustments (consisting of normal recurring
adjustments) necessary for a fair statement in all material respects of the
results for the interim periods presented. The results of operations for the
nine months ended September 30, 1996 are not necessarily indicative of results
to be expected for the full year.
 
                                     F-10
<PAGE>
 
                 KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
  Certain financial statement items in the interim 1995 period have been
reclassified to conform to the interim 1996 presentation.
 
NOTE 2--AFFILIATED PROGRAMS AND MANAGED PROPERTIES
 
  Kelley Partners. From Kelley Oil's inception in April 1983 until January
1986, its principal business was managing certain public and private drilling
programs (the "Original Drilling Programs") in return for management fees and
overhead reimbursements. Kelley Partners became actively engaged in business
in January 1986 following the consummation of an exchange offer (the "KLY
Exchange") for interests in the Original Drilling Programs.
 
  General Partner Interests in Kelley Partners and Kelley Operating. Through
its ownership in Kelley Oil, the Company had a 1.99% general partner interest
in Kelley Partners, and David L. Kelley, the former Chairman and Chief
Executive Officer of Kelley Oil, had a .01% general partner interest. The
general partner interests in Kelley Partners were retained by Kelley Oil and
Mr. Kelley after the Consolidation and were eliminated in the Partnership
Merger. In connection with the Partnership Merger, Kelley Partners' 98%
limited partner interest in Kelley Operating was transferred to Kelley Oil,
and Petrofunds, Inc., an indirect wholly owned subsidiary of the Company, was
substituted for Mr. Kelley as special general partner of Kelley Operating. In
accordance with a severance arrangement, Mr. Kelley received a payment of
$70,000 from Kelley Oil in March 1996 attributable to his terminated interests
in Kelley Partners and Kelley Operating. Kelley Oil has remained the managing
general partner of Kelley Operating, with a general partner interest of 1.99%.
 
  DDPs. Kelley Oil's activities were expanded after the KLY Exchange to
include the management of Kelley Partners and DDPs (collectively, the "Kelley
Group"). In accordance with the partnership agreement of Kelley Partners,
Kelley Oil sponsored one DDP in each year from 1987 through 1992 (the "1987
DDP" through the "1992 DDP") and a seventh DDP in 1994 (the "1994 DDP"). See
Note 9--DDPs.
 
  Units Issued in Exchange Offers. Each year from 1990 through 1994, Kelley
Partners issued Units in an exchange offer (each, a "DDP Exchange") for
interests in a DDP. Information on the last two DDP Exchanges is presented in
the following table.
 
                     SUMMARY INFORMATION ON DDP EXCHANGES
 
                               ($ IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                                             1990       1991
                                                          ----------  ---------
DDP                                                          DDP         DDP
EXCHANGE DATA                                              EXCHANGE   EXCHANGE
-------------                                             ----------  ---------
<S>                                                       <C>         <C>
Total DDP equity (including GPs)......................... $   30,702     35,833
Kelley Oil investment.................................... $   20,999     25,850
Kelley Oil ownership interest............................       68.4%      72.1%
Effective date of DDP Exchange...........................     7/1/93     7/1/94
Total DDP Exchange value................................. $   27,289     18,748
Market price per Unit.................................... $    18.93       7.55
Units issued by Kelley Partners..........................  1,443,845  2,486,755
DDP distributions plus DDP Exchange value................ $   50,662     36,306
Units issued to Kelley Oil...............................    986,261  1,791,293
</TABLE>
 
  Primarily as a result of Units received in DDP Exchanges, Kelley Oil and its
subsidiaries owned a total of 3.9 million Units in Kelley Partners as of
December 31, 1994, representing approximately 16.58% of the Units
 
                                     F-11
<PAGE>
 
                 KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

outstanding at that time. In the Consolidation, Kelley Oil retained its Units
in Kelley Partners, and KOGC acquired all outstanding Units held by the Public
Unitholders.
 
  Reimbursements from Affiliated Programs and Managed Properties. Kelley Oil
is reimbursed for direct expenses paid on behalf of its subsidiary
partnerships and other working interest owners of properties operated by
Kelley Oil, and for all appropriate administrative and overhead expenses
incurred in connection with the management and administration of each of these
affiliated programs and managed properties. Included in these amounts are
reimbursements for allocated administrative and overhead expenses, net of
intercompany eliminations, aggregating $2.0 million, $1.9 million and $1.6
million in 1993, 1994 and 1995, respectively. Reimbursements for direct costs
associated with lease acquisition, exploration and drilling activities during
1993, 1994 and 1995 aggregated $9.8 million, $9.9 million and $6.1 million,
respectively.
 
  Other Reimbursements. The Company is reimbursed for direct costs incurred
and advanced in connection with financing and acquisitions on behalf of the
Group. These reimbursements aggregated $2.1 million and $1.3 million in 1993
and 1994, respectively, and are recorded as a reduction of general and
administrative expenses. No reimbursements were made for these costs in 1995.
 
NOTE 3--LONG-TERM DEBT
 
  Direct and Indirect Long-Term Debt. The Company's long-term debt at December
31, 1994 and 1995 is comprised of the following items of direct and guaranteed
indebtedness of Kelley Oil plus indirect debt representing its proportionate
interest in long-term debt of affiliated partnerships. See Note 5--
Stockholders' Equity (Deficit) and Note 8--Employee Stock Ownership Plan.
 
                                (IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                                                  DECEMBER 31,
                                                                ----------------
                                                                  1994    1995
                                                                -------- -------
<S>                                                             <C>      <C>
Bank credit facilities......................................... $ 27,931  22,000
ESOP bank term loans...........................................    1,021      --
Proportionate interest KLY Subordinated Debt...................   10,761  47,054
Senior Notes...................................................       --  95,926
                                                                -------- -------
                                                                  39,713 164,980
  Less current maturities......................................    2,471      --
                                                                -------- -------
                                                                $ 37,242 164,980
                                                                ======== =======
</TABLE>
 
  Bank Credit Facilities. Prior to the Consolidation, Kelley Oil maintained a
revolving credit facility of up to $15 million with a commercial bank, bearing
interest at a floating rate equal to bank's prime and requiring payments of
interest only until the scheduled maturity on July 1, 1996. In May 1994,
Kelley Oil repaid its borrowings under the facility from part of the proceeds
from a public offering of its $2.625 convertible exchangeable preferred stock
("KOIL $2.625 Preferred Stock"). In August 1994, the 1992 DDP was added as a
borrower under the facility, and the borrowing base was reduced to $6 million,
all of which was advanced to the 1992 DDP to fund part of its drilling
expenditures in excess of contributed capital. Borrowings under the facility
were secured by the pledge of substantially all the assets of the 1992 DDP and
Kelley Oil, other than its Units in Kelley Partners. At December 31, 1994, the
Company's proportionate interest in bank borrowings by the 1992 DDP was
approximately $5 million.
 
  Kelley Oil maintained a second credit facility with a commercial lender
prior to the Consolidation, providing for loans up to $10 million, subject to
monthly borrowing base redeterminations on the basis of the
 
                                     F-12
<PAGE>
 
                 KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

market value of Kelley Oil's Units in Kelley Partners collateralizing the
facility. The facility provided for payments of interest at 1/2% above a
specified prime until July 23, 1998, when borrowings under the facility were
scheduled to be converted to a term loan payable over two years. As of
December 31, 1994, $9 million was outstanding under this facility.
 
  As of December 31, 1994, Kelley Partners had outstanding bank debt $69.9
million and publicly held subordinated debt in the outstanding face amount of
$61.2 million. The Company's proportionate interest in the subordinated debt
and revolving bank debt of Kelley Partners at December 31, 1994 aggregated
$12.2 million and $13.9 million, respectively.
 
  In connection with the Consolidation, KOGC completed a refinancing in
February 1995 for the outstanding bank debt of Kelley Partners, Kelley Oil and
the 1992 DDP. The refinancing was provided by Kelley Partners' prior lending
banks under a $70 million revolving credit facility (the "Prior Credit
Facility") and a $20 million term loan facility (the "Term Facility"). The
borrowers under the facilities were Kelley Operating and Kelley Oil. Kelley
Partners, KOGC and its other subsidiary partnerships were guarantors.
Borrowings of $90 million under the two facilities were used to refinance
Kelley Partners' bank debt of $69.9 million, Kelley Oil's debt of $9 million
under one of its credit facilities and borrowings of $6 million by the 1992
DDP, with the balance of $5.1 million used to fund payables of Kelley Partners
and KOGC, including part of the expenses for the Consolidation. Borrowings
under the Prior Credit Facility were reduced by $10 million in February 1995
from part of the proceeds of an equity private placement by KOGC.
 
  Interest was payable on borrowings under the Prior Credit Facility at a
floating rate equal to 1/2% above the agent bank's prime rate or, at the
election of the Company, 2 1/2% above a quoted Libor rate, together with a
quarterly commitment fee initially equal to 5/8% per annum of the unused
borrowing base. Interest was payable on borrowings under the Term Facility at
a floating rate initially equal to 3 1/2% above the agent bank's prime rate.
 
  In June 1995, proceeds from a public offering of KOGC's 13 1/2% Senior Notes
due June 15, 1999 in the aggregate principal amount of $100 million (the
"Senior Notes") were used to repay all outstanding borrowings under the two
facilities, and the Term Facility was terminated. The agreement covering the
Prior Credit Facility was amended at that time to (i) reduce the credit limit
to $40 million, (ii) reduce the interest rate to the agent bank's prime rate
or, at the election of the Company, a rate ranging from 1 1/4% to 1 3/4% above
a quoted Libor rate, together with a quarterly commitment fee equal to 3/8%
per annum of the unused borrowing base, (iii) eliminate all financial
covenants other than a working capital maintenance requirement and a
limitation on accounts payable above a specified level and (iv) conform the
borrowing base limitations with debt restrictions under the indenture for the
Senior Notes, resulting in a reduction of the borrowing base to $35 million.
 
  In January 1996, the agreement covering the Prior Credit Facility was
further amended to (i) reduce the credit limit to $35 million, (ii) generally
limit the use of future borrowings to reduce trade payables, (iii) increase
the interest rate to 2% above the agent's prime rate and (iv) add certain
financial covenants. The financial covenants added to the Prior Credit
Facility included a current ratio test that KOGC would have been unable to
satisfy at the initial measuring date on May 15, 1996 without a substantial
equity infusion.
 
  In February 1996, KOGC repaid outstanding bank borrowings of $30 million
with proceeds from an equity infusion and replaced the Prior Credit Facility
with a $35 million revolving credit facility from a new bank group (the
"Credit Facility"). Interest on borrowings under the Credit Facility is
payable at a rate equal to (i) the higher of 1/2% above the agent bank's prime
rate or 1% above the federal funds rate in effect from time to time or (ii) at
the Company's election, 1 1/2% above a quoted Libor rate, together with a
quarterly commitment fee equal to 3/8% per annum of the unused portion of the
available borrowing base. The agreement for the Credit Facility requires the
payment of interest only until March 15, 1999, when all borrowings will be
repayable, subject to mandatory prepayment with net proceeds from asset sales
in excess of related borrowing base reductions.
 
                                     F-13
<PAGE>
 
                 KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
  The borrowers under the Credit Facility are Kelley Operating and Kelley Oil.
KOGC and its other subsidiary partnerships are guarantors. Borrowings under
the Credit Facility are secured by mortgages on all of the oil and gas and
pipeline assets of the Company and its subsidiaries, together with a security
interest in production proceeds from oil and gas sales. The agreement covering
the Credit Facility prohibits the payment of dividends, requires the consent
of the lenders for third-party borrowings or extraordinary transactions and
provides financial covenants of KOGC including a maximum ratio of total funded
debt to earnings before interest, taxes and noncash charges ranging from 6.0
to 1.0 in 1996 to 3.5 to 1.0 after September 30, 1997 and a minimum cash
interest coverage ratio ranging from 1.1 to 1.0 in 1996 to 2.0 to 1.0 after
September 30, 1997.
 
  ESOP Loans. The Company maintains the ESOP to purchase and hold qualifying
securities for the accounts of its employees. To finance the purchase of those
securities, the ESOP obtained term loans maturing in portions through June 28,
1997, bearing interest at rates of prime plus 1% and 85% of that rate and
secured at December 31, 1994 by .2 million shares of KOIL ESOP Preferred
Stock. The ESOP term loans were guaranteed by Kelley Oil and aggregated $1.0
million as of December 31, 1994. The balance of the ESOP debt was repaid in
1995.
 
  KLY Subordinated Debt. Prior to the Partnership Merger, Kelley Partners had
outstanding 8 1/2% Convertible Subordinated Debentures due April 1, 2000 in
the aggregate principal amount of $26.9 million ("8 1/2% Debentures") and 7
7/8% Convertible Subordinated Notes due 1999 in the aggregate principal amount
at maturity of $34.4 million (the "7 7/8% Notes"). Under the terms of the
Consolidation, the 8 1/2% Debentures and 7 7/8% Notes became convertible into
the Company's Common Stock or a combination of Common and Preferred Stock
instead of Units based on the exchange ratios for the Units in the
Consolidation. In connection with the Partnership Merger, the 8 1/2%
Debentures and 7 7/8% Notes became direct obligations of KOGC.
 
  Senior Notes. In June 1995, KOGC issued $100 million principal amount of its
Senior Notes and applied its net proceeds from the offering primarily to repay
outstanding bank debt of $90 million and fund drilling operations. The Senior
Notes are senior unsecured obligations of the Company, guaranteed by Kelley
Oil, Kelley Operating and, prior to the Partnership Merger, by Kelley
Partners. The indenture for the Senior Notes generally limits additional
borrowings by the Company and its subsidiaries to the greater of 12 1/2% of
adjusted consolidated net tangible assets or $30 million for working capital
purposes plus $5 million per year for capital expenditures. The Company's
ability to borrow the additional $5 million per year for capital expenditures
and to pay dividends on its Preferred Stock is conditioned upon the absence of
declines in oil and gas reserves from estimated volumes at December 31, 1995.
That condition was not satisfied for 1996. The Senior Note indenture also
contains a number of other covenants that include limitations on mergers and
asset transfers, dividend and other payments and use of proceeds from asset
sales.
 
  Debenture Conversions and Exchanges. During 1993, a total of 2,485,446
shares of Kelley Oil's common stock ("KOIL Common Stock") were issued upon
conversion of $21.9 million principal amount of its 11 1/2% Convertible
Subordinated Debentures due September 1, 2002 (the "KOIL 11 1/2% Debentures")
at a temporarily reduced conversion price. A noncash charge of $2.1 million
was recognized to account for those conversions, together with an additional
charge of $.4 million for related transaction costs. In August 1994, Kelley
Oil offered the remaining holders of KOIL 11 1/2% Debentures and Kelley Oil's
outstanding 8% Convertible Subordinated Debentures due September 1, 2001
(collectively, the "KOIL Debentures") shares of KOIL $2.625 Preferred Stock in
exchange for their KOIL Debentures. A total of .4 million shares of KOIL
$2.625 Preferred Stock were issued during September 1994 in exchange for all
of the outstanding KOIL Debentures. Each share of KOIL $2.625 Preferred Stock
was converted into one share of the Company's Preferred Stock in the
Consolidation.
 
  Interest Payments. Cash payments attributable to interest on all
indebtedness, excluding the ESOP loans, aggregated $4.7 million, $3.0 million
and $14.2 million for the years ended December 31, 1993, 1994 and 1995,
respectively. In addition, the ESOP paid interest on its indebtedness
aggregating $.2 million, $.1 million and $57,000 during 1993, 1994 and 1995,
respectively.
 
                                     F-14
<PAGE>
 
                 KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
  Debt Maturities. At December 31, 1995, outstanding borrowings of $22 million
under the Prior Credit Facility were scheduled for repayment on January 31,
1997. After giving effect to the February 1996 refinancing of the Prior Credit
Facility, the Company had no debt maturities prior to 1999, with aggregate
debt maturities in 1999 and 2000 of $134.4 million and $26.9 million,
respectively.
 
NOTE 4--LEASES
 
  The Company leases office space, computer equipment and automobiles under
operating leases expiring May 14, 1998 with options to renew. Rental expenses
related to these leases for the years ended December 31, 1993, 1994 and 1995
were $2.2 million, $2.3 million and $1.9 million, respectively. For the
balance of the lease terms minimum rentals are as follows:
 
                                (IN THOUSANDS)
<TABLE>
      <S>                                                                 <C>
      1996............................................................... $1,402
      1997...............................................................  1,155
      1998...............................................................    476
                                                                          ------
        Total............................................................ $3,033
                                                                          ======
</TABLE>
 
  In December 1995, the Company adopted a plan to change its policy of
providing automobiles and related expense reimbursements to key employees in
order to lower associated costs. Under the plan, KOGC canceled its automobile
leases in February 1996 and provided employees the option to purchase the cars
at 90% of the 1996 NADA loan value. The foregoing table reflects the reduction
in KOGC's obligations under its car leases resulting from this change in its
automobile policy.
 
NOTE 5--STOCKHOLDERS' EQUITY (DEFICIT)
 
  Common Stock Private Placement. In February 1995, KOGC completed an
institutional private placement of 4 million shares of its Common Stock.
Proceeds of $16 million from the private placement were used to fund drilling
activities and for working capital. Pending application, $10 million of the
proceeds were used to reduce borrowings under the Prior Credit Facility.
 
  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 KOGC
and Contour (the "Contour Transaction"). The newly issued shares represent
49.8% of KOGC's voting power. In connection with the Contour Transaction, the
Company (i) entered into an Option Agreement with Contour (the "Contour Option
Agreement"), (ii) obtained consents from its principal stockholders, subject
to compliance with applicable securities law, to amend its Certificate of
Incorporation to increase its authorized Common Stock from 100 million shares
to 200 million shares, (iii) entered into employment agreements with John F.
Bookout, President of Contour, and three other new executives named by him,
(iv) adopted a Nonqualified Stock Option Plan for the new executives other
than Mr. Bookout, (v) amended its existing Incentive Stock Option Plans, (vi)
reduced the size of its board of directors (the "Board") to seven members and
reconstituted the Board with three continuing directors and four designees of
Contour and (vii) replaced the Prior Credit Facility with the new 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 KOGC debt repurchase or redemption obligations as a result
of the purchase (a "Debt Event"). A Debt Event would occur upon (i) a "Change
of Control" as defined in the indenture for the Senior Notes, (ii)
 
                                     F-15
<PAGE>
 
                 KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

a "Change in Control" as defined in the indenture for the 7 7/8% Notes or
(iii) a "Redemption Event" as defined in the indenture for the 8 1/2%
Debentures. A Debt Event with respect to either series of Notes or the 8 1/2%
Debentures would entitle each holder of the affected securities to require the
repurchase or redemption of the holder's securities. Contour is required to
exercise the Contour Option for the Maximum Option Number within 30 days after
it concludes in its sole discretion that a Debt Event would not occur as a
result of the purchase. While the exercise of the Contour Option would not
cause a Debt Event under the indenture for the 8 1/2% Debentures, waivers from
the holders of the Senior Notes and 7 7/8% Notes or amendments to the Debt
Event provisions of their indentures will require consents from holders of a
majority in aggregate principal amount of each series of Notes.
 
  Preferred Stock. In May 1994, Kelley Oil completed a public offering of 1.4
million shares of KOIL $2.625 Preferred Stock at $25 per share. The shares
were convertible into KOIL Common Stock at a conversion price of $7.20 per
share and exchangeable after April 1995 at Kelley Oil's option for its 10 1/2%
Convertible Subordinated Debentures due 2004. Net proceeds from the public
offering aggregated $32.5 million, of which $19.0 million was used to repay
outstanding borrowings under Kelley Oil's credit facilities and the balance
was applied primarily to finance ongoing drilling operations through its
investment in the 1994 DDP. In September 1994, an additional .4 million shares
of KOIL $2.625 Preferred Stock were issued in exchange for outstanding KOIL
Debentures. During 1994, Kelley Oil paid quarterly dividends on outstanding
KOIL $2.625 Preferred Stock at the rate of $.65625 per share, aggregating $2.0
million. Each outstanding share of KOIL $2.625 Preferred Stock was converted
in the Consolidation into one share of KOGC's Preferred Stock, which has the
same terms as the KOIL $2.625 Preferred Stock except for expanded voting
rights.
 
  The Company issued .6 million shares of its Preferred Stock to Public
Unitholders in the Consolidation, resulting in a total of 2.4 million
outstanding shares of Preferred Stock after giving effect to the shares issued
to holders of KOIL $2.625 Preferred Stock. During 1995, KOGC paid quarterly
dividends on its outstanding Preferred Stock at the rate of $.65625 per share,
aggregating $6.0 million. In January 1996, the Company suspended the payment
of the quarterly Preferred Stock dividend scheduled for February 1, 1996 to
conserve cash. Future dividends on the Preferred Stock are prohibited under
the agreement covering the Credit Facility. Although no interest is payable on
Preferred Stock arrearages, the terms of the Preferred Stock enable holders,
voting separately as a class, to elect two additional directors to the Board
at each meeting of stockholders at which directors are to be elected during
any period when Preferred Stock dividends are in arrears in an aggregate
amount equal to at least six quarterly dividends, whether or not consecutive.
 
  Each share of Preferred Stock is convertible, at the holder's option, into
3.4722 shares of Common Stock, equivalent to a conversion price of $7.20 per
share of Common Stock relative to the $25 per share liquidation preference of
the Preferred Stock (the "Preferred Conversion Price"). Under the terms of the
Certificate of Designation governing the Preferred Stock, the Contour
Transaction triggered a special conversion right under which the Preferred
Conversion Price was reduced to $4.00 for a period of 45 days commencing March
12, 1996.
 
  ESOP Preferred Stock. From 1987 through 1992, a total of 3.4 million shares
of KOIL ESOP Preferred Stock in four separate series were issued to the ESOP
for a total of $8.9 million. Each share of KOIL ESOP Preferred Stock had
voting rights equivalent to one share of KOIL Common Stock. The KOIL ESOP
Preferred Stock was convertible into KOIL Common Stock, at any time at the
option of the ESOP, at the rate of one share of KOIL Common Stock for each
share of KOIL ESOP Preferred Stock. During 1994, Kelley Oil paid quarterly
dividends on outstanding KOIL ESOP Preferred Stock at rates ranging from
$.0375 per share to $.25 per share, aggregating $.9 million for the year,
which were used to service ESOP loans. In January 1995, a total of 1.1 million
shares of KOIL ESOP Preferred Stock were converted into the same number of
shares of KOIL Common Stock upon distribution to employees affected by the
year-end restructuring.
 
                                     F-16
<PAGE>
 
                 KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
  The outstanding shares of KOIL ESOP Preferred Stock were converted in the
Consolidation into four equivalent series of the Company's cumulative
convertible preferred stock ("ESOP Preferred Stock"), which ranks junior in
dividend and liquidation rights to the Company's Preferred Stock. Each share
of ESOP Preferred Stock is convertible into one share of Common Stock. During
1995, KOGC paid quarterly dividends on outstanding ESOP Preferred Stock at
rates ranging from $.0375 per share to $.25 per share, aggregating $.6 million
for the year. Dividends on the ESOP Preferred Stock during the first three
quarters of 1995 were used to service ESOP loans, which were repaid in full at
the end of the third quarter. A dividend paid in the fourth quarter of 1995
plus the ESOP contribution for the quarter were invested in a certificate of
deposit. As of December 31, 1995, 1.9 million shares of ESOP Preferred Stock
were outstanding. Future dividends on ESOP Preferred Stock are prohibited
under the agreement covering the Credit Facility. See Note 3--Long Term Debt.
 
  Incentive Stock Option Plans. Kelley Oil maintained Incentive Stock Option
Plans (the "Plans") adopted in 1987 (the "1987 Plan") and 1991 (the "1991
Plan"), each providing for the grant of options to purchase up to .5 million
shares of KOIL Common Stock to key employees. Under the 1987 Plan, options to
purchase a total of .2 million shares of the KOIL Common Stock at an average
exercise price of $1.10 per share were granted during 1988, and options to
purchase a total of .3 million shares of KOIL Common Stock at an exercise
price of $2.00 per share were granted in 1989. Under the 1991 Plan, options to
purchase a total of .2 million shares of KOIL Common Stock were granted in
1991 at an exercise price of $7 5/8 per share and repriced to the extent
outstanding at $4 1/8 per share in February 1995. The 1987 Plan and the 1991
Plan (collectively, the "Prior Plans") were assumed by KOGC in the
Consolidation.
 
  The Board adopted a third Incentive Stock Option Plan in May 1995 (the "1995
Plan"), providing for the grant of options to purchase up to 1.5 million
shares of Common Stock to key employees. Under the 1995 Plan, options to
purchase a total of 1.1 million shares of Common Stock at $2 3/8 per share
were granted in October 1995, and options to purchase a total of .4 million
shares of Common Stock at $1 3/4 per share were granted in November 1995. The
1995 Plan was approved by principal stockholders of the Company in February
1996, together with an amendment to Prior Plans and the 1995 Plan
(collectively, the "ISO Plans") extending the period during which terminated
employee may exercise vested options to three years after termination of
employment.
 
  The option price for options granted under the ISO Plans is fixed by the
Compensation Committee of the Board (the "Committee") at the fair market value
of the underlying stock at the time of the grant. Each option granted under
the ISO Plans is exercisable during the term of the optionee's employment for
up to ten years from the date of grant. During 1993 and 1994, options to
purchase a total of .1 million and .1 million shares, respectively, of KOIL
Common Stock were exercised at prices ranging from $1.10 to $7 5/8. Options to
purchase a total of .2 million shares of Common Stock were exercised during
1995 at prices ranging from $1.10 to $2.00.
 
  Nonqualified Stock Option Plan. The Board adopted a Nonqualified Stock
Option Plan (the "NSO Plan") in January 1996 in accordance with the terms of
the Contour Purchase Agreement, which provides for the grant of options to
purchase an aggregate of 2.5 million shares of Common Stock at an exercise
price of $1.00 per share to new senior executives designated by Mr. Bookout.
Options vesting over three years were issued to those executives for all of
the covered shares under the NSO Plan at the closing under the Contour
Purchase Agreement in February 1996. The NSO Plan is administered by the
Committee, which has authority to prohibit an option exercise if it determines
that the purchase would result in a Debt Event. The NSO Plan was approved by
principal stockholders of the Company in February 1996.
 
                                     F-17
<PAGE>
 
                 KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
NOTE 6--INCOME TAXES
 
  The following table sets forth a reconciliation of the statutory federal
income tax with the income tax provision under SFAS 109:
 
                                (IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                                     1993     1994      1995
                                                   --------  -------  --------
<S>                                                <C>       <C>      <C>
Loss before income taxes.......................... $(25,223) (24,957) (211,291)
Income tax benefit computed at statutory rates....   (8,576)  (8,485)  (71,839)
  Increase in valuation allowance.................    8,456    7,524    71,236
Permanent differences:
  Nondeductible expenses..........................       82      922       567
  Amortization....................................       33       33        33
  Other-net.......................................        5        6         3
                                                   --------  -------  --------
  Tax benefit..................................... $     --       --        --
                                                   ========  =======  ========
</TABLE>
 
  Federal income taxes paid for the year ended December 31, 1993 were $50,000.
No federal income taxes were paid for the years ended December 31, 1994 and
1995.
 
  Deferred Income Taxes. Deferred income tax provisions for the years ended
December 31, 1993, 1994 and 1995 result from the following temporary
differences:
 
                                (IN THOUSANDS)
 
<TABLE>
<CAPTION>
                            1993    1994    1995
                           ------  ------  -------
<S>                        <C>     <C>     <C>
Temporary differences
 related to oil & gas
 properties:
  Intangible drilling
   costs.................. $5,034   4,985    6,387
  Depreciation and
   depletion.............. (5,082) (5,540) (58,276)
  Exploration and dry hole
   costs.................. (4,837) (2,517)  (8,508)
  Lease rentals...........    180     260     ----
  Leasehold write-offs....  1,106   1,152    1,611
  Partnership income......   (661)   (419)    ----
Net operating loss
 carryforward benefit..... (4,195) (5,418) (12,434)
Valuation allowance.......  8,456   7,524   71,236
Other.....................     (1)    (27)     (16)
                           ------  ------  -------
  Total deferred tax
   benefit................ $   --      --       --
                           ======  ======  =======
</TABLE>
 
                                     F-18
<PAGE>
 
                 KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
  KOGC'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>
                                                       1993    1994     1995
                                                      ------  -------  -------
<S>                                                   <C>     <C>      <C>
Deferred tax liabilities:
  Tax over book depletion, depreciation and
   capitalization methods on oil and gas properties.. $7,184    5,093       --
Deferred tax assets:
  Book over tax depletion, depreciation and
   capitalization methods on oil and gas properties..     --       --   53,312
  Net operating loss carryforwards................... 16,928   22,346   35,181
  Charitable contribution carryforwards..............    126      142      138
  Alternative minimum tax credit carryforwards.......     21       21       21
  Valuation allowance................................ (9,891) (17,416) (88,652)
                                                      ------  -------  -------
  Total deferred tax assets..........................  7,184    5,093       --
                                                      ------  -------  -------
Net deferred tax liability........................... $   --       --       --
                                                      ======  =======  =======
</TABLE>
 
  Net Operating Loss Carryforwards and Alternative Minimum Tax Credits. As of
December 31, 1995, the Company had cumulative net operating loss carryforwards
("NOL") for federal income tax purposes of approximately $100 million and net
operating loss carryforwards for alternative minimum tax purposes of
approximately $64 million. Due to the 1995 ownership change in KOGC in
connection with the Consolidation, future utilization of the net operating
loss carry forwards may be limited by Internal Revenue Code section 382. KOGC
also had approximately $21,000 of alternative minimum tax credit
carryforwards, which have no expiration date. These carryforwards will be
available for use by KOGC through the expiration dates indicated below.
 
                                (IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                                   ALTERNATIVE         NET
                                                   MINIMUM TAX    OPERATING LOSS
                                                NOL CARRYFORWARDS CARRYFORWARDS
                                                ----------------- --------------
<S>                                             <C>               <C>
2000...........................................      $    --             206
2001...........................................           --              26
2002...........................................           --           1,343
2003...........................................           --             234
2004...........................................           --           1,500
2005...........................................           --              --
2006...........................................           --          14,540
2007...........................................        4,831          16,483
2008...........................................       11,002          12,163
2009...........................................       14,685          16,250
2010...........................................       33,662          37,182
                                                     -------          ------
  Total........................................      $64,180          99,927
                                                     =======          ======
</TABLE>
 
                                     F-19
<PAGE>
 
                 KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
NOTE 7--RELATED PARTY TRANSACTIONS
 
  Lafayette Gas Intrastate. The Company earned approximately $.1 million
through CGI in each of 1993 and 1994 for managing the pipeline facilities of
an affiliated joint venture, Lafayette Gas Intrastate. These fees were
discontinued after 1994. The Company's proportionate interests in gas sales by
the Kelley Group for resale through Lafayette Gas Intrastate were $.3 million,
$.3 million and $.5 million for the years ended December 31, 1993, 1994 and
1995, respectively.
 
  Interest on DDP Commitments. During 1993, 1994 and 1995, Kelley Oil paid or
accrued interest at a market rate in the amounts, net of intercompany
elimination, of $.1 million, $.1 million and $.2 million, respectively, on
deferred subscription commitments to DDPs. See Note 9--DDPs.
 
NOTE 8--EMPLOYEE STOCK OWNERSHIP PLAN
 
  Kelley Oil established the ESOP effective January 1, 1984 for the benefit of
substantially all of its employees. Kelley Oil guaranteed the ESOP loans
referred to in Note 3--Long-Term Debt (collectively, the "ESOP Loans") and
recorded deferred employee compensation balances in a like amount, which were
deducted from stockholders' equity. Prior to 1996, Kelley Oil made
contributions to the ESOP for covered employees in amounts up to 15% of their
annual salaries up to a specified level. Contribution expense is recognized
using the cash payments method. Cumulative expense under this method is
greater than 80% of the cumulative expense that would have been recognized
under the shares allocated method before deduction of dividends. Contributions
and dividend payments on the KOIL ESOP Preferred Stock and ESOP Preferred
Stock were used to make scheduled payments of principal and interest on the
ESOP Loans, which were repaid in full during 1995. For the years ended
December 31, 1993, 1994 and 1995, Kelley Oil paid to the ESOP contributions of
$1.1 million, $1.2 million and $.7 million, respectively, plus dividends of
$.9 million, $.9 million and $.6 million, respectively. As the term loans were
repaid, a corresponding portion of the stock pledged to secure the loans was
released and allocated among the participants' accounts. As of December 31,
1995, the ESOP owned 1.9 million shares of ESOP Preferred Stock and .5 million
shares of Common Stock, all of which were allocated to participants' accounts.
See Note 5--Stockholders' Equity (Deficit).
 
 
                                     F-20
<PAGE>
 
                 KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
NOTE 9--DDPS
 
  Structure of Development Partnerships. Kelley Oil and Mr. Kelley are the
general partners of the DDPs, with general partner interests of 3.94% and
 .02%, respectively, for which they contributed a proportionate amount of
capital. In addition, Kelley Oil had undertaken to purchase for its own
investment account all units in DDPs that were not subscribed preemptively by
Unitholders of Kelley Partners. The DDPs have no officers, directors or
employees and utilize the management and staff of Kelley Oil for all
management and administrative functions. Interests in the first five DDPs
sponsored between 1987 and 1991 were acquired in separate DDP Exchanges by
Kelley Partners each year from 1990 through 1994. See Note 2--Affiliated
Programs and Managed Properties.
 
  The 1994 DDP. In February 1994, the 1994 DDP completed a public offering of
20.9 million units of its limited and general partner interests at $3.00 per
unit. As of March 15, 1996, Kelley Oil owned 19.2 million units (91.85%) in
the 1994 DDP, together with its 3.94% general partner interest, and officers
and directors of Kelley Oil owned 47,100 units (.23%). Kelley Oil's
subscription for units in the 1994 DDP, together with its 3.94% general
partner interest, represented a commitment aggregating $60.1 million or 92.15%
of the 1994 DDP's total committed capital (the "KOIL Share"), with other
unitholders committing for the balance or 7.85% of the 1994 DDP's total
committed capital (the "Outside Share"), payable in each case 10% on
subscription and the balance through the end of November 1994. As of December
31, 1995, Kelley Oil had contributed $31.3 million to the 1994 DDP.
 
  The 1994 DDP's partnership agreement provides that any contributions of the
partners not used or committed to be used for drilling activities during the
two-year period from the commencement of operations through February 29, 1996
(the "Commitment Period") shall be distributed to the partners on a pro rata
basis as a return of capital. Based on the amount of committed capital
actually used and committed to drilling activities by the end of the
Commitment Period, Kelley Oil determined the adjusted level of committed
partnership capital at $60.7 million in accordance with the 1994 DDP's
partnership agreement, and the 1994 DDP then distributed the Outside Share of
uncommitted capital to its unitholders other than Kelley Oil aggregating $.3
million in March 1996 as a return of capital. Because the KOIL Share of
committed capital exceeded its capital contributions at that time, Kelley Oil
did not receive a distribution of uncommitted capital. Kelley Oil intends to
contribute the unfunded portion of its commitment, currently aggregating $17.2
million after giving effect to the reduction in the 1994 DDP's committed
capital, together with interest, as funds are needed for completion of the
1994 DDP's drilling program.
 
  The 1992 DDP. During November 1992, the 1992 DDP completed a public offering
of 16.0 million units of limited and general partner interests at $3.00 per
unit. As of March 15, 1996, Kelley Oil owned 13.4 million units (83.72%) in
the 1992 DDP, together with its 3.94% general partner interest, and officers
and directors of Kelley Oil owned 51,500 units (.32%). As of December 31,
1995, the 1992 DDP was indebted to Kelley Oil for loans and reimbursement
obligations aggregating $8.1 million.
 
NOTE 10--COMMITMENTS AND CONTINGENCIES
 
  During 1995, the Company entered into change of control agreements with 16
employees entitling them to severance benefits in the event their employment
is terminated under certain circumstances within two years after a change of
control, as defined in the agreements. For this purpose, the February 1996
closing under the Contour Purchase Agreement constituted a change of control.
See Note 5--Stockholders' Equity. The severance benefits amount to salary
continuation for 12 to 24 months, depending on seniority of the covered
employees, based on their highest compensation rate during the two years prior
to termination. The Company's anticipated liability under these agreements as
of February 29, 1996 was $2.7 million.
 
                                     F-21
<PAGE>
 
                 KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
  The Company is involved from time to time in various claims and lawsuits
incidental to its business. In the opinion of management, the ultimate
liability thereunder, if any, will not have a material effect on the financial
statements of the Company.
 
NOTE 11--LITIGATION SETTLEMENT
 
  Following Kelley Oil's announcement of the initial proposal for the
Consolidation in August 1994, four separate lawsuits were filed against Kelley
Oil and its directors relating to the Consolidation and the 1991 DDP Exchange.
In November 1994, Kelley Oil entered into a memorandum of understanding with
the plaintiffs in three of the lawsuits, providing for a proposed settlement
based on a revised Consolidation proposal negotiated by a special committee of
Kelley Oil's nonmanagement directors and the settling plaintiffs. A
stipulation and agreement of compromise, settlement and release reflecting the
terms of the proposed settlement was filed in the United States District Court
for the Southern District of Texas on November 23, 1994. At a hearing held on
the same date, the court approved the consolidation of all four lawsuits and
the certification of a Unitholder class requested by the settling parties. On
March 3, 1995, following a hearing on the fairness of the settlement, the
court entered a final order approving the settlement, dismissing the
consolidated lawsuits with prejudice and reducing the award of attorneys' fees
and disbursements contemplated by the stipulation to $1.5 million payable $.3
million in cash and the balance in Common Stock. The Company believes a
pending appeal by the non-settling plaintiff is without merit.
 
NOTE 12--HEDGING ACTIVITIES
 
  The Company periodically uses forward sales contracts and derivative
financial instruments covering natural gas to reduce exposure to downward
price fluctuations on natural gas production. For the first nine months of
1996, through a combination of natural gas swap agreements and forward sales
contracts, approximately 69.4% (unaudited) of Kelley's anticipated natural gas
production was affected by hedging transactions at an average NYMEX quoted
price of $2.17 (unaudited) per MMBTU before transaction and transportation
costs on gas delivered under forward sales contracts. Approximately 57.6%
(unaudited) of Kelley's anticipated natural gas production for the balance of
1996 had been hedged through swap agreements or forward sales contracts at an
average NYMEX quoted price of $2.25 (unaudited) per MMBTU before transaction
and transportation costs on gas delivered under forward sales contracts. The
natural gas 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. No significant realized gains or
losses were deferred at December 31, 1994 or 1995.
 
  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.
 
                                     F-22
<PAGE>
 
                 KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
NOTE 13--PRO FORMA DATA FOR THE CONSOLIDATION AND THE CONTOUR TRANSACTION
        (UNAUDITED)
 
  The Consolidation. The Consolidation was recorded as of February 7, 1995 for
financial accounting purposes. The following table presents unaudited pro
forma results of the Company's operations for the years ended December 31,
1994 and 1995 as if the Consolidation had occurred on January 1, 1994. The pro
forma financial information does not purport to represent what the Company's
results of operations actually would have been had the Consolidation occurred
on such date or to project the Company's results of operations for or at any
future period or date.
 
                     (IN THOUSANDS, EXCEPT PER SHARE DATA)
 
<TABLE>
<CAPTION>
                            YEAR ENDED
                           DECEMBER 31,
                         -----------------
                          1994      1995
                         -------  --------
<S>                      <C>      <C>
Revenues (net).......... $43,986    41,276
Net loss applicable to
 common and common
 equivalent shares...... (53,236) (218,549)
Net loss per share......   (1.39)    (5.07)
</TABLE>
 
  The Contour Transaction. The Company issued 48 million shares of Common
Stock at $1.00 per share to Contour in February 1996 in connection with the
Contour Transaction. See Note 5--Stockholders' Equity (Deficit). The following
table reflects the unaudited pro forma results of the Company's operations for
the years ended December 31, 1994 and 1995 as well as the nine months ended
September 30, 1996 as if the Contour Transaction had occurred on January 1,
1994.
 
                     (IN THOUSANDS, EXCEPT PER SHARE DATA)
 
<TABLE>
<CAPTION>
                                                YEAR ENDED        NINE MONTHS
                                               DECEMBER 31,          ENDED
                                             ------------------  SEPTEMBER 30,
                                               1994      1995        1996
                                             --------  --------  -------------
<S>                                          <C>       <C>       <C>
Net loss applicable to common and common
 equivalent shares.......................... $(51,436) (217,389)    (11,939)
Net loss per share..........................     (.60)    (2.39)       (.13)
</TABLE>
 
NOTE 14--SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND GAS EXPLORATION,
        DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)
 
  This footnote provides unaudited information required by Statement of
Financial Accounting Standards No. 69, "Disclosures about Oil and Gas
Producing Activities."
 
                                     F-23
<PAGE>
 
                 KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
  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,
                                                   --------------------------
                                                    1993     1994      1995
                                                   -------  -------  --------
<S>                                                <C>      <C>      <C>
Unevaluated properties............................ $ 1,749    1,430    13,050
Properties subject to amortization................  92,830  129,883   287,970
                                                   -------  -------  --------
Capitalized costs.................................  94,579  131,313   301,020
Accumulated depreciation, depletion and
 amortization..................................... (38,846) (59,108) (173,996)
                                                   -------  -------  --------
Net capitalized costs............................. $55,733   72,205   127,024
                                                   =======  =======  ========
</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,
                                                          ----------------------
                                                           1993    1994   1995
                                                          ------- ------ -------
<S>                                                       <C>     <C>    <C>
Property acquisition costs:(1)(2)
  Proved................................................. $ 4,393  7,035 126,577
  Unproved...............................................     163    309  88,539
Exploration costs........................................  13,389  8,760   9,521
Development costs........................................  22,254 28,034  31,730
                                                          ------- ------ -------
  Total costs incurred................................... $40,199 44,138 256,367
                                                          ======= ====== =======
</TABLE>
--------
(1) Includes general and administrative costs directly related to acquisition,
    exploration and development of oil and gas properties of $3.0 million,
    $2.9 million and $3.2 million incurred in the years ended December 31,
    1993, 1994 and 1995, respectively.
(2) Includes assets acquired in the Consolidation aggregating $207 million for
    the year ended December 31, 1995.
 
  Results of Operations. Results of operations for the Company's oil and gas
producing activities are summarized below.
 
                                (IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                                     YEAR ENDED DECEMBER 31,
                                                    ---------------------------
                                                      1993     1994      1995
                                                    --------  -------  --------
<S>                                                 <C>       <C>      <C>
Oil and gas revenues............................... $ 19,711   15,487    36,042
Gain on sale of oil and gas properties.............       --       --       777
Production costs...................................   (3,993)  (3,760)  (10,835)
Exploration and dry hole costs.....................  (14,226)  (7,404)  (23,387)
Depreciation, depletion and amortization...........  (18,424) (19,997)  (34,355)
Impairment of oil and gas properties...............       --       --  (150,138)
                                                    --------  -------  --------
Results of operations.............................. $(16,932) (15,674) (181,896)
                                                    ========  =======  ========
</TABLE>
 
                                     F-24
<PAGE>
 
                 KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
  Reserves. Results of operations from oil and gas producing activities are
determined using actual historical revenues, production costs (including
production related taxes), exploration and dry hole costs and depreciation,
depletion and amortization of the capitalized costs subject to amortization.
General and administrative expenses and interest expense are excluded from
this determination of results of operations. Income tax benefit is computed by
applying the statutory tax rates to earnings before income tax expense with
recognition of tax credits and allowances relating to oil and gas producing
activities. No income tax benefit was recognized during the reported periods.
 
  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, are summarized below.
 
<TABLE>
<CAPTION>
                            CRUDE OIL, CONDENSATE
                           AND NATURAL GAS LIQUIDS         NATURAL GAS
                                   (MBBLS)                    (MMCF)
                           -------------------------  ------------------------
                            1993     1994     1995     1993     1994    1995
                           -------  -------  -------  -------  ------  -------
<S>                        <C>      <C>      <C>      <C>      <C>     <C>
Proved developed and
 undeveloped reserves:
  Beginning of year.......   1,837    1,114    1,236   69,804  64,875   93,612
  Revisions of previous
   estimates..............    (913)      75     (558) (23,177) 16,055  (27,006)
  Dilutive effect of
   offerings..............    (210)      --       --   (5,030)     --       --
  Purchases of oil and gas
   properties.............      --       --    1,756       --      --  127,962
  Revisions of purchased
   oil and gas
   properties.............      --       --     (766)      --      --  (37,021)
  Extensions and
   discoveries............     602      218      156   30,605  19,379   66,864
  Sale of oil and gas
   properties.............      --       --     (118)      --      --  (10,388)
  Production..............    (202)    (171)    (319)  (7,327) (6,697) (17,750)
                           -------  -------  -------  -------  ------  -------
  End of year.............   1,114    1,236    1,387   64,875  93,612  196,273
                           =======  =======  =======  =======  ======  =======
Proved developed reserves
 at end of year...........     602      674    1,197   30,092  48,482  111,287
                           =======  =======  =======  =======  ======  =======
</TABLE>
 
  The reported changes in net proved reserves during 1995 include downward
year-end revisions on developed and undeveloped south Louisiana properties
aggregating 11.6 Bcfe and 39.6 Bcfe, respectively, and a mid-year divestiture
of nonstrategic properties accounting for approximately 11.1 Bcfe. These
declines were partially offset by 13.6 Bcfe of reserve additions from
successful drilling in north Louisiana and the addition of 52.2 Bcfe from 36
proved undeveloped locations in core north Louisiana fields. As a result of
its continuing operating losses and a net decline of 35.9 Bcfe in its proved
reserves at December 31, 1995 from year-earlier pro forma levels, the Company
performed an assessment of the carrying value of its oil and gas properties
under FAS 121 indicating an impairment should be recognized as of year end.
See Note 1--Summary of Significant Accounting Policies. Based on this
analysis, KOGC recognized noncash impairment charges against the carrying
values of its proved and unproved oil and gas properties under FAS 121
aggregating $83.4 million and $66.7 million, respectively, at December 31,
1995.
 
                                     F-25
<PAGE>
 
                 KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
  Standardized Measure. The table of the Standardized Measure of Discounted
Future Net Cash Flows relating to the Company's ownership interests in proved
oil and gas reserves as of year-end is shown below.
 
                                (IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                                      AS OF DECEMBER 31,
                                                   ---------------------------
                                                     1993     1994      1995
                                                   --------  -------  --------
<S>                                                <C>       <C>      <C>
Future cash inflows..............................  $176,876  175,052   431,351
Future production costs..........................   (26,442) (34,472)  (76,021)
Future development costs.........................   (17,556) (22,914)  (36,524)
Future income tax expenses.......................   (16,480)  (6,016)   (8,577)
                                                   --------  -------  --------
Future net cash flows............................   116,398  111,650   310,229
10% annual discount for estimating timing of cash
 flows...........................................   (44,608) (40,810) (139,177)
                                                   --------  -------  --------
Standardized measure of discounted future net
 cash flows......................................  $ 71,790   70,840   171,052
                                                   ========  =======  ========
</TABLE>
 
  Future cash inflows are computed by applying year-end prices of oil and gas
to year-end quantities of proved oil and gas reserves. Future production and
development costs are computed primarily by the Company's petroleum engineers
by estimating the expenditures to be incurred in developing and producing the
Company's proved oil and gas reserves at the end of the year, based on year-
end costs and assuming continuation of existing economic conditions.
 
  Future income taxes are based on year-end statutory rates, adjusted for
operating loss carryforwards and tax credits. A discount factor of 10% was
used to reflect the timing of future net cash flows. The standardized measure
of discounted future net cash flows is not intended to represent the
replacement cost or fair market value of the Company's oil and gas properties.
 
  The standardized measure of discounted future net cash flows as of December
31, 1993, 1994 and 1995 was calculated using prices in effect as of those
dates, which averaged $13.80, $15.65 and $19.73, respectively, per barrel of
oil and $2.49, $1.66 and $2.06, respectively, per Mcf of natural gas.
 
                                     F-26
<PAGE>
 
                 KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
  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,
                             --------------------------
                               1993     1994     1995
                             --------  -------  -------
<S>                          <C>       <C>      <C>
Changes due to current year
 operations:
  Sales of oil and gas, net
   of production costs...... $(15,718) (11,727) (25,207)
  Sale of oil and gas
   properties...............       --       --   (5,884)
  Extensions and
   discoveries..............   34,382   16,290   62,407
  Dilutive effect of equity
   offerings................  (12,404)      --       --
  Purchases of oil and gas
   properties...............       --       --   90,660
  Future development costs
   incurred.................    8,460    7,242   10,216
Changes due to revisions in
 standardized variables:
  Prices and production
   costs....................   (4,877) (20,609)  21,055
  Revisions of previous
   quantity estimates.......  (44,258)   3,432  (22,223)
  Revisions of purchased oil
   and gas properties.......       --       --  (28,199)
  Estimated future
   development costs........   (3,411)  (1,949)  17,676
  Income taxes..............   17,041    6,104     (893)
  Accretion of discount.....    9,029    7,179    7,145
  Production rates (timing)
   and other................   (6,746)  (6,912) (26,541)
                             --------  -------  -------
    Net increase
     (decrease).............  (18,502)    (950) 100,212
  Beginning of year.........   90,292   71,790   70,840
                             --------  -------  -------
  End of year............... $ 71,790   70,840  171,052
                             ========  =======  =======
</TABLE>
 
  Sales of oil and gas, net of production costs, are based on historical pre-
tax results. Extensions and discoveries, purchases of minerals in place and
the changes due to revisions in standardized variables are reported on a pre-
tax discounted basis, while the accretion of discount is presented after tax.
Extensions and discoveries include proved undeveloped reserves attributable to
Kelley Oil's interests in drill sites assigned to DDPs but do not give effect
to the Consolidation prior to 1995.
 
NOTE 15--EQUITY INFUSION (UNAUDITED)
 
  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 KOGC and Contour (the "Contour
Transaction"). The newly issued shares represented 49.8% of KOGC's voting
power at the time of the Contour Transaction. In connection with the Contour
Transaction, 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 KOGC debt repurchase or
redemption obligations as a result of the purchase (a "Debt Event"). Contour
is required to exercise the Contour Option for the Maximum Option Number
within 30 days after it concludes in its sole discretion that a Debt Event
would not occur as a result of the purchase.
 
  A Debt Event would occur upon (i) a "Change of Control" as defined in the
indenture for the Company's 13 1/2% Senior Notes due 1999 (the "Senior
Notes"), (ii) a "Change in Control" as defined in the indenture for the
Company's 7 7/8% Convertible Subordinated Notes due 1999 (the "7 7/8% Notes")
or (iii) a "Redemption Event" as defined in the indenture for the Company's
8 1/2% Convertible Subordinated Debentures due 2000 (the
 
                                     F-27
<PAGE>
 
                 KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

"8 1/2% Debentures"). A Debt Event would entitle each holder of the affected
securities to require the repurchase or redemption of the holder's securities.
While the current exercise of the Contour Option would not cause a Debt Event
under the indenture for the 8 1/2% Debentures, it would require waivers or
consents from the holders of a majority in aggregate principal amount of the
Senior Notes and 7 7/8% Notes.
 
NOTE 16--PREFERRED AND ESOP PREFERRED STOCK CONVERSIONS (UNAUDITED)
 
  Under the terms of the Certificate of Designation governing the Company's
$2.625 Convertible Exchangeable Preferred Stock (the "Public Preferred
Stock"), the Contour Transaction triggered a special conversion right under
which the conversion price was reduced to $4.00 for a period of 45 days
commencing March 13, 1996. In April 1996, .7 million shares of Preferred Stock
were converted into 4.4 million shares of the Company's Common Stock.
 
  In January 1996, the Company suspended the payment of the quarterly Public
Preferred Stock dividend scheduled for February 1, 1996. Future dividends on
the Public Preferred Stock are prohibited under the agreement covering the
Company's credit facility. As of June 30, 1996, $2.3 million or $1.31 per
share in dividends were in arrears, increasing the total liquidation value to
$45.9 million.
 
  The Company had four outstanding series of Cumulative Convertible Preferred
Stock ("ESOP Preferred Stock"), which ranked junior in dividend and
liquidation rights to the Public Preferred Stock. In June 1996, each of the
outstanding 1.9 million shares of ESOP Preferred Stock was redeemed for one
share of the Company's Common Stock.
 
NOTE 17--EMPLOYEE STOCK OPTIONS (UNAUDITED)
 
  In October 1995, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation" ("FAS 123"), which established financial accounting and
reporting standards for stock-based employee compensation plans and for
transactions in which an entity issues its equity instruments to acquire goods
and services from nonemployees. FAS 123 requires, among other things, that
compensation cost be calculated for fixed stock options at the grant date by
determining fair value using an option-pricing model. The Company has the
option of recognizing the compensation cost over the vesting period as an
expense in the consolidated statement of operations or making pro forma
disclosures in the notes to financial statements reflecting the effects on net
earnings as if the compensation cost had been recognized in the consolidated
statement of operations. In February 1996 in conjunction with the Contour
Transaction, the Company granted options to purchase 2.5 million shares of
Common Stock at $1.00 per share. The Company adopted FAS 123 in 1996 and will
make the required pro forma disclosures in the notes to its annual financial
statements.
 
NOTE 18--RESTRUCTURING EXPENSE (UNAUDITED)
 
  In the second quarter of 1996, the Company incurred a $2 million
restructuring charge associated primarily with staff reductions and related
severance settlements of 12 employees and various reorganization costs, of
which $.5 million has been paid through September 30, 1996. These charges
along with charges incurred in prior periods are included in accounts payable
and accrued expenses on the balance sheet in the amount of $1.8 million, of
which $.1 million is associated with restructuring charges incurred in prior
periods.
 
                                     F-28
<PAGE>
 
                         KELLEY OIL & GAS CORPORATION
 
                    UNAUDITED PRO FORMA FINANCIAL STATEMENT
 
  The accompanying Unaudited Pro Forma Statement of Loss of Kelley Oil & Gas
Corporation (the "Company") sets forth certain pro forma financial information
with respect to the consolidation (the "Consolidation") of Kelley Oil & Gas
Partners, Ltd. ("Kelley Partners") and Kelley Oil Corporation ("Kelley Oil")
and the Refinancing (as defined in this Offering Memorandum). The Unaudited
Pro Forma Statement of Loss for the year ended December 31, 1995 presents the
results of operations of the Company as if the Consolidation and the
Refinancing had been consummated on January 1, 1995 and June 15, 1995 (the
issue date of the Notes), respectively. Capitalized terms not otherwise
defined herein have the meanings ascribed to them in the Prospectus of which
this Unaudited Pro Forma Statement of Loss is a part.
 
  The Consolidation has been accounted for as a purchase of the Public
Unitholders' interests in Kelley Partners by the Company through Kelley Oil,
whose stockholders received a majority of the total voting securities issued
in the Consolidation. The purchase price was allocated on the basis of fair
value attributable to proved and unproved properties.
 
  Future results may vary significantly from the amounts reflected in the
following information due to economic factors, production or price
differences, future activities of the Company and other matters. The pro forma
financial information presented below is unaudited and gives effect to the
Consolidation and the Refinancing as of January 1, 1994. The pro forma
financial information does not purport to represent what the Company's results
of operations actually would have been had the Consolidation and the
Refinancing occurred on such date or to project the Company's results of
operations for or at any future period or date. Although the Consolidation
resulted in a reduction of general and administrative costs, no pro forma
adjustments have been reflected because cost reduction plans were not been
completed at the time of the Consolidation. The Unaudited Pro Forma Financial
Statements should be read in conjunction with the Notes to the Unaudited Pro
Forma Statement of Loss and the Consolidated Financial Statements and related
Notes of the Company included herein.
 
                                     F-29
<PAGE>
 
                          KELLEY OIL & GAS CORPORATION
 
                     UNAUDITED PRO FORMA STATEMENT OF LOSS
 
                      FOR THE YEAR ENDED DECEMBER 31, 1995
                                  (UNAUDITED)
                   (IN THOUSANDS, EXCEPT PER UNIT/SHARE DATA)
 
<TABLE>
<CAPTION>
                                        KELLEY
                                       PARTNERS
                                      PERIOD FROM                                             THE
                          KELLEY OIL  JANUARY 1,                 THE COMPANY              COMPANY PRO
                          YEAR ENDED    1995 TO    ADJUSTMENTS    PRO FORMA               FORMA AFTER
                         DECEMBER 31, FEBRUARY 7,    FOR THE       BEFORE    REFINANCING      THE
                             1995        1995     CONSOLIDATION  REFINANCING ADJUSTMENTS  REFINANCING
                         ------------ ----------- -------------  ----------- -----------  -----------
<S>                      <C>          <C>         <C>            <C>         <C>          <C>
  Oil and gas revenues..  $  36,042      3,129         (621)(A)     38,550        --         38,550
  Pipeline and gas
   marketing
   revenues, net........        956          3           (1)(A)        958        --            958
  Gain on sale of oil
   and gas properties...        777         --           --            777        --            777
  Interest and other
   income...............        986          6           (1)(A)        991        --            991
                          ---------     ------       ------       --------      ----       --------
    Total revenues......     38,761      3,138         (623)(A)     41,276        --         41,276
                          ---------     ------       ------       --------      ----       --------
  Production expenses...     10,835        781         (155)(A)     11,461        --         11,461
  Exploration costs.....     23,387        410          (70)(A)     23,727        --         23,727
  General and
   administrative
   expenses, net........      7,030        459          (91)(A)      7,398        --          7,398
  Interest and other
   debt expense.........     21,956      1,006         (199)(A)     22,763      (604)(B)     22,159
  Restructuring
   expenses.............      1,115         --           --          1,115        --          1,115
  Impairment of oil and
   gas properties.......    150,138         --           --        150,138        --        150,138
  Depreciation,
   depletion and
   amortization.........     35,591      2,997       (2,398)(C)     36,190        --         36,190
                          ---------     ------       ------       --------      ----       --------
    Total costs and
     expenses...........    250,052      5,653       (2,913)       252,792      (604)       252,188
                          ---------     ------       ------       --------      ----       --------
Net loss................  $(211,291)    (2,515)       2,290       (211,516)      604       (210,912)
Less:
  Cumulative preferred
   stock
   dividends, net.......      6,607         --          426 (D)      7,033        --          7,033
                          ---------     ------       ------       --------      ----       --------
Net loss applicable to
 units, common stock,
 and common stock
 equivalent shares
 outstanding(E).........   (217,898)    (2,515)       1,864       (218,549)      604       (217,945)
                          =========     ======                    ========                 ========
Net loss limited
 partners...............         --     (2,415)                         --
Net loss general
 partners...............         --       (100)                         --
Net loss per
 share/limited partners
 unit...................      (5.31)     (0.11)                      (5.07)                   (5.05)
Average units, common
 stock and equivalent
 shares outstanding(F)..     41,032     23,352                      43,123                   43,123
                          =========     ======                    ========                 ========
</TABLE>
 
              See Notes to Unaudited Pro Forma Statement of Loss.
 
 
                                      F-30
<PAGE>
 
                         KELLEY OIL & GAS CORPORATION
 
                NOTES TO UNAUDITED PRO FORMA STATEMENT OF LOSS
 
  (A) To eliminate Kelley Oil's average proportionate interest in Kelley
Partners' revenues and expenses during 1995.
 
  (B) As adjusted to give effect to the Refinancing. To adjust for the
refinancing as if it occurred on January 1, 1996, historical interest expense
for the nine months ended September 30, 1996 would decrease by $0.8 million or
$.01 per share. On a pro forma basis at September 30, 1996, the Company's
long-term debt and stockholders' deficit would be $176.8 million and $31.0
million, respectively. See "Capitalization".
 
  (C) To recalculate depreciation, depletion and amortization for the year
ended December 31, 1995, on a combined versus historical basis using the unit
of production method.
 
  (D) To reflect pro forma dividends on the Public Preferred Stock at a per
share annual rate of $2.625, aggregating $.4 million for the year ended
December 31, 1995.
 
  (E) Net losses were incurred for the year ended December 31, 1995, on a
historical and pro forma basis. In addition, the tax basis of the Company's
assets exceeded the financial accounting basis of its assets. Accordingly, no
provision for income taxes is recognized for the year ended December 31, 1995,
and no deferred tax liability existed at year end. The net deferred tax assets
on a pro forma basis for the year ended December 31, 1995 are fully offset by
a valuation allowance.
 
  (F) Pro forma average primary shares of Common Stock outstanding reflect a
total of 20.6 million shares of Common Stock issued to the Public Unitholders
in the Consolidation. Pro forma fully-diluted information is not presented
because the effects are antidilutive.
 
                                     F-31
<PAGE>
 
                         INDEPENDENT AUDITORS' REPORT
 
To the Partners of Kelley Oil & Gas Partners, Ltd.
 
  We have audited the consolidated balance sheets of Kelley Oil & Gas
Partners, Ltd. (a Texas limited partnership) as of December 31, 1993 and 1994,
and the related accompanying statements of loss, partners' equity and cash
flows for each of the two years in the period ended December 31, 1994. These
financial statements are the responsibility of management. Our responsibility
is to express an opinion on these financial statements based on our audits.
 
  We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the 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, the consolidated financial statements referred to above
present fairly, in all material respects, the consolidated financial position
of Kelley Oil & Gas Partners, Ltd. at December 31, 1993 and 1994, and the
consolidated results of their operations and their cash flows for each of the
two years in the period ended December 31, 1994, in conformity with generally
accepted accounting principles.
 
  As discussed in Note 1 to the consolidated financial statements in 1994, the
Partnership changed its method of accounting for oil and gas producing
activities.
 
                                          Ernst & Young LLP
 
Houston, Texas
March 6, 1995
 
 
                                     F-32
<PAGE>
 
                        KELLEY OIL & GAS PARTNERS, LTD.
 
                          CONSOLIDATED BALANCE SHEETS
 
                                 (IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                                              DECEMBER 31,
                                                           -------------------
                                                              1993      1994
                                                           ---------- --------
                                                           (RESTATED)
<S>                                                        <C>        <C>
ASSETS:
  Cash and cash equivalents:..............................  $  1,011  $    897
  Accounts receivable - trade.............................     2,102     1,612
  Accounts receivable - affiliates........................     5,203     4,745
  Prepaid assets..........................................       426        --
  Other current assets....................................       633       287
                                                            --------  --------
    Total current assets..................................     9,375     7,541
                                                            --------  --------
  Oil and gas properties, successful efforts method:
    Unevaluated, net......................................     8,168     7,199
    Properties subject to amortization....................   312,434   375,058
  Pipelines and other transportation assets, at cost......     7,962     7,910
                                                            --------  --------
                                                             328,564   390,167
                                                            --------  --------
  Less: Accumulated depreciation, depletion and
   amortization...........................................  (154,066) (192,378)
                                                            --------  --------
    Total oil and gas properties and pipeline assets,
     net..................................................   174,498   197,789
                                                            --------  --------
  Other assets............................................       253       184
                                                            --------  --------
    TOTAL ASSETS..........................................  $184,126  $205,514
                                                            ========  ========
LIABILITIES:
  Accounts payable and accrued expenses - trade...........  $  6,462  $ 10,257
  Accounts payable - affiliates...........................       702    12,423
  Notes payable - current.................................        --     4,430
                                                            --------  --------
    Total current liabilities.............................     7,164    27,110
                                                            --------  --------
  Notes payable-long-term.................................    23,000    65,470
  Convertible subordinated debentures.....................    25,437    25,664
  Convertible subordinated notes..........................    27,622    28,520
  Minority interest.......................................         9        --
                                                            --------  --------
    TOTAL LIABILITIES.....................................    83,232   146,764
                                                            --------  --------
PARTNERS' EQUITY:
  Limited Partners' equity, 20,864, 23,352 and 23,352
   Units outstanding at December 31, 1993, 1994 and
   February 7, 1995.......................................   107,376    67,589
  General Partners' equity (deficit)......................    (6,482)   (8,839)
                                                            --------  --------
    TOTAL PARTNERS' EQUITY................................   100,894    58,750
                                                            --------  --------
  TOTAL LIABILITIES AND PARTNERS' EQUITY..................  $184,126  $205,514
                                                            ========  ========
</TABLE>
 
                See Notes to Consolidated Financial Statements.
 
 
                                      F-33
<PAGE>
 
                        KELLEY OIL & GAS PARTNERS, LTD.
 
                        CONSOLIDATED STATEMENTS OF LOSS
 
                      (IN THOUSANDS, EXCEPT PER UNIT DATA)
 
<TABLE>
<CAPTION>
                               YEARS ENDED        PERIOD FROM
                               DECEMBER 31,     JANUARY 1, 1995
                            ------------------      THROUGH
                               1993     1994    FEBRUARY 7, 1995
                            ---------- -------  ----------------
                            (RESTATED)            (UNAUDITED)
<S>                         <C>        <C>      <C>
REVENUES:
Oil and gas sales:
  Affiliates..............   $ 27,618   24,242        3,129
  Other...................      6,359    6,468           --
                             --------  -------       ------
                               33,977   30,710        3,129
Pipeline revenues.........      3,781    3,819            3
Other income..............         62      219            6
                             --------  -------       ------
  Total revenues..........     37,820   34,748        3,138
                             --------  -------       ------
Cost of gas sold..........      3,503    3,833           --
Lease operating expenses..      8,681    8,719          594
Severance taxes...........      1,494    1,613          187
Exploration costs.........     15,404   12,712          410
General and administrative
 expenses.................      2,764    3,239          459
Interest and other debt
 expense..................      7,112    8,736        1,006
Accretion of discount.....        601      659           --
Depreciation, depletion
 and amortization.........     30,452   37,851        2,997
                             --------  -------       ------
  Total costs and
   expenses...............     70,011   77,362        5,653
                             --------  -------       ------
NET LOSS..................   $(32,191) (42,614)      (2,515)
                             ========  =======       ======
NET LOSS ALLOCABLE TO
 LIMITED PARTNERS.........   $(30,917) (40,926)      (2,415)
                             ========  =======       ======
NET LOSS ALLOCABLE TO
 GENERAL PARTNERS.........   $ (1,274)  (1,688)        (100)
                             ========  =======       ======
NET LOSS PER UNIT.........   $  (1.75)   (1.85)        (.11)
                             ========  =======       ======
Average Units
 outstanding..............     17,637   22,118       23,352
                             ========  =======       ======
</TABLE>
 
                See Notes to Consolidated Financial Statements.
 
 
                                      F-34
<PAGE>
 
                        KELLEY OIL & GAS PARTNERS, LTD.
 
                     CONSOLIDATED STATEMENTS OF CASH FLOWS
 
                                 (IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                               YEARS ENDED        PERIOD FROM
                                               DECEMBER 31,     JANUARY 1, 1995
                                            ------------------      THROUGH
                                               1993     1994    FEBRUARY 7, 1995
                                            ---------- -------  ----------------
                                            (RESTATED)            (UNAUDITED)
<S>                                         <C>        <C>      <C>
OPERATING ACTIVITIES:
Net loss..................................   $(32,191) (42,614)      (2,515)
Adjustments to reconcile net loss to net
 cash provided by operating activities:
  Depreciation, depletion and
   amortization...........................     30,452   37,851        2,997
  Dry hole and impairment costs...........      8,102    5,052          (15)
  Amortization of debenture and note
   offering costs.........................        478      479           40
  Accretion of note discount..............        601      659           59
  Changes in operating assets and
   liabilities net of effects of exchange
   offers:
  Decrease (increase) in accounts
   receivable.............................      3,411    2,227         (461)
  Decrease (increase) in prepaid and other
   current assets.........................       (491)     772          (86)
  Decrease (increase) in other non-current
   assets.................................       (253)      69            4
  Increase (decrease) in accounts payable
   and accrued expenses...................     (9,349)   7,497        2,618
                                             --------  -------       ------
Net cash provided by operating
 activities...............................        760   11,992        2,641
                                             --------  -------       ------
INVESTING ACTIVITIES:
Purchases of property and equipment.......    (36,072) (42,529)      (1,963)
Sales (purchases) of pipeline and other
 transportation assets....................     (1,316)      52           --
Cash received in exchange offers..........      1,897    1,310           --
Sale of other non-current assets..........        389      461           30
                                             --------  -------       ------
Net cash used in investing activities.....    (35,102) (40,706)      (1,933)
                                             --------  -------       ------
FINANCING ACTIVITIES:
Proceeds from long term borrowings........     51,000   46,900           --
Principal payments on long term
 borrowings...............................    (40,000)      --           --
Minority interest in subsidiaries.........         (4)      --           --
Capital contributed by partners...........     51,739       --           --
Distributions to partners.................    (21,906) (16,910)          --
Syndication costs charged to equity.......     (6,728)  (1,377)          (9)
Note offering costs.......................       (202)     (13)          --
                                             --------  -------       ------
Net cash provided by (used in) financing
 activities...............................     33,899   28,600           (9)
                                             --------  -------       ------
Increase (decrease) in cash and cash
 equivalents..............................       (443)    (114)         699
Cash and cash equivalents, beginning of
 period...................................      1,454    1,011          897
                                             --------  -------       ------
Cash and cash equivalents, end of period..   $  1,011      897        1,596
                                             ========  =======       ======
</TABLE>
 
                See Notes to Consolidated Financial Statements.
 
 
                                      F-35
<PAGE>
 
                        KELLEY OIL & GAS PARTNERS, LTD.
 
             CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' EQUITY
 
                                 (IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                                   LIMITED   GENERAL
                                                   PARTNERS  PARTNERS  TOTAL
                                                   --------  -------- -------
<S>                                                <C>       <C>      <C>
Partners' equity (deficit) at January 1, 1993..... $ 85,494   (4,341)  81,153
                                                   --------   ------  -------
Capital contributed...............................   79,028       --   79,028
Issuance of 102,560 Units upon conversion of
 subordinated notes and debentures................    1,538       --    1,538
Syndication costs.................................   (6,728)      --   (6,728)
Distributions.....................................  (21,039)    (867) (21,906)
Net loss..........................................  (30,917)  (1,274) (32,191)
                                                   --------   ------  -------
Partners' equity (deficit) at December 31, 1993... $107,376   (6,482) 100,894
                                                   --------   ------  -------
Capital contributed...............................   18,757       --   18,757
Syndication costs.................................   (1,377)      --   (1,377)
Distributions.....................................  (16,241)    (669) (16,910)
Net loss..........................................  (40,926)  (1,688) (42,614)
                                                   --------   ------  -------
Partners' equity (deficit) at December 31, 1994... $ 67,589   (8,839)  58,750
                                                   --------   ------  -------
Capital contributed...............................        0        0        0
Syndication costs.................................       (9)       0       (9)
Distributions.....................................        0        0        0
Net loss..........................................   (2,415)    (100)  (2,515)
                                                   --------   ------  -------
Partners' equity (deficit) at February 7, 1995.... $ 65,165   (8,939)  56,226
                                                   ========   ======  =======
</TABLE>
 
 
 
                See Notes to Consolidated Financial Statements.
 
                                      F-36
<PAGE>
 
                        KELLEY OIL & GAS PARTNERS, LTD.
 
            NOTES TO CONSOLIDATED AND INTERIM FINANCIAL STATEMENTS
 
NOTE 1--SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
  Organization. Kelley Oil & Gas Partners, Ltd., a Texas limited partnership
("Kelley Partners"), was formed to acquire through an exchange offer (the "KLY
Exchange") the oil and gas properties in 21 programs (the "Original Programs")
managed or sponsored by Kelley Oil Corporation ("Kelley Oil") and its
affiliates or predecessors. Upon consummation of the KLY Exchange in January
1986, Kelley Partners issued its units representing limited partner interests
("Units") to participants in exchange for their interests in the Original
Programs.
 
  Kelley Oil is the managing general partner of Kelley Partners, and David L.
Kelley, the Chairman and Chief Executive Officer of Kelley Oil, is the special
general partner of Kelley Partners. Kelley Oil and Mr. Kelley have general
partner interests of 1.99% and 0.01%, respectively, in Kelley Partners.
 
  Kelley Partners operates through Kelley Operating Company, Ltd., a Texas
limited partnership ("Kelley Operating"). Kelley Partners contributes the
assets received by it in exchange offers and other financings to Kelley
Operating in exchange for a 98% limited partner interest in Kelley Operating.
Kelley Oil and David L. Kelley are the general partners of Kelley Operating
with interests of 1.99% and 0.01%, respectively.
 
  The general partner interests of Kelley Oil and Mr. Kelley in Kelley
Partners and Kelley Operating aggregate 3.96% on a combined basis. As of
December 31, 1994, Kelley Oil and its subsidiaries also owned 3.9 million
Units or approximately 16.6% of the then outstanding Units in Kelley Partners,
which they received in the KLY Exchange for their interests in certain of the
Original Programs and in various subsequent exchange offers. In addition, as
of December 31, 1994, Kelley Oil's officers and directors owned 591,020 Units
in Kelley Partners.
 
  In February 1995, Unitholders in Kelley Partners voted to approve a
consolidation of the equity ownership of Kelley Partners and Kelley Oil (the
"Consolidation") into Kelley Oil & Gas Corporation ("KOGC"). Pursuant to the
Consolidation, each Unit held by investors other than Kelley Oil and its
subsidiaries was converted into 1.2188 shares of KOGC's common stock ("KOGC
Common Stock") or, at the election of the holder, .609 of a share of KOGC
Common Stock and .127 of a share of KOGC's $2.625 convertible exchangeable
preferred stock ("KOGC Preferred Stock"). Stockholders of Kelley Oil also
received capital stock of KOGC in the Consolidation. As a result of the
Consolidation, Kelley Oil became a wholly owned subsidiary of KOGC, and Kelley
Partners became a 99.98% owned subsidiary partnership of KOGC. Following the
Consolidation, Mr. Kelley continues to own a .01% general partner interest in
both Kelley Partners and Kelley Operating, and Kelley Partners' publicly held
subordinated debt remains outstanding. See Note 4--Equity and Debt Offerings.
 
  Kelley Partners and Kelley Operating have no officers, directors or
employees. The officers and employees of Kelley Oil perform the management and
administrative functions of Kelley Partners and Kelley Operating. Kelley
Partners and Kelley Operating reimburse Kelley Oil for all direct costs
incurred in managing their operations and all indirect costs (principally
general and administrative expenses) allocable to the partnerships.
 
  Basis of Presentation. The accompanying consolidated financial statements
include Kelley Partners and Lafayette Gas Intrastate, a joint venture in which
Kelley Partners owns a 99.99% interest. All significant intercompany
transactions and accounts have been eliminated upon consolidation. The
financial statements of Kelley Partners include the combined financial
position, results of operations, cash flows and changes in partners' equity of
Kelley Partners and Kelley Operating. Management believes that presenting the
financial statements of Kelley Partners and Kelley Operating on a combined
basis is more meaningful because it provides a more comprehensive view of the
financial position and results of operations attributable to the assets
contributed by Kelley Partners to Kelley Operating.
 
                                     F-37
<PAGE>
 
                        KELLEY OIL & GAS PARTNERS, LTD.
 
      NOTES TO CONSOLIDATED AND INTERIM FINANCIAL STATEMENTS--(CONTINUED)

  Revenue Recognition. Kelley Partners recognizes oil and gas revenue from its
interests in producing wells as oil and gas from those wells is produced and
sold. Oil and gas sold is not significantly different from Kelley Partners'
share of production.
 
  Cash and Cash Equivalents. Kelley Partners considers all highly liquid
investments with a maturity date of three months or less when purchased to be
cash equivalents.
 
  Derivative Financial Instruments. From time to time, Kelley Oil has entered
into transactions in derivative financial instruments covering future natural
gas production on behalf of Kelley Partners principally as a hedge against
natural gas price declines. Realized and unrealized gains and losses are
recorded in other assets or liabilities until the underlying natural gas is
produced and sold, at which time those gains and losses are included in oil
and gas revenues. See Note 10--Hedging Activities.
 
  Income Taxes. Kelley Partners is a partnership and, as a result, the income
or loss of Kelley Partners for federal income tax purposes is includable in
the tax returns of the individual partners. Accordingly, no recognition has
been given to income taxes in the accompanying financial statements.
 
  Oil and Gas Properties. Oil and gas properties are located in the United
States. During the third quarter of 1994, Kelley Partners changed from the
full cost method to the successful efforts method of accounting for its oil
and gas operations. Although the full cost method continues to be generally
accepted, the Financial Accounting Standards Board has expressed a preference
for the successful efforts method. Under current conditions, management
believes the successful efforts method provides a more appropriate measure of
its oil and gas operations. The accompanying consolidated balance sheet as of
December 31, 1993 and related consolidated statements of loss, partners'
equity and cash flows for the years ended December 31, 1992 and 1993 have been
restated to reflect the new method.
 
  Under the successful efforts method, the costs of successful wells,
development dry holes and productive leases are capitalized and amortized on a
unit-of-production basis over the life of the related reserves. Cost centers
for amortization purposes are determined on a field-by-field basis. Estimated
future abandonment and site restoration costs, net of anticipated salvage
values, are taken into account in depreciation, depletion and amortization.
Unproved properties with significant acquisition costs are periodically
assessed for impairment in value, with any impairment charged to expense.
 
  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.
 
  The successful efforts method also imposes limitations on the carrying or
book value of proved oil and gas properties and requires an impairment
provision or noncash charge against earnings for any quarter in which their
carrying value exceeds the standardized measure of undiscounted future net
cash flows from proved oil and gas reserves based on prices received for oil
and gas production as of the end of that quarter or a subsequent date prior to
publication of financial results for the quarter.
 
                                     F-38
<PAGE>
 
                        KELLEY OIL & GAS PARTNERS, LTD.
 
      NOTES TO CONSOLIDATED AND INTERIM FINANCIAL STATEMENTS--(CONTINUED)
 
  Adoption of the successful efforts accounting method resulted in changes to
previously reported net loss and net loss per Unit as follows:
 
                     (IN THOUSANDS, EXCEPT PER UNIT DATA)
 
<TABLE>
<CAPTION>
                                                                   DECEMBER 31,
                                                                       1993
                                                                   ------------
<S>                                                                <C>
Net loss previously reported......................................   $(41,272)
Adjustment for the effect of the change in accounting method......      9,081
                                                                     --------
  Net loss as restated............................................   $(32,191)
                                                                     ========
Net loss per Unit previously reported.............................   $  (2.25)
Adjustment for the effect of the change in accounting method......        .50
                                                                     --------
  Net loss per Unit as restated...................................   $  (1.75)
                                                                     ========
</TABLE>
 
  If the full cost method of accounting had been retained, Kelley Partners
would have reported a net loss for 1994 of $96.4 million or $4.19 per Unit.
Results under the full cost method would have included the effect of full cost
ceiling writedowns of approximately $86.5 million in 1994. As a result of the
accounting change, net property, plant and equipment and partners' equity were
each increased by $58.5 million as of December 31, 1994 compared to the
amounts that would have been reflected after the writedown under the full cost
method as of that date.
 
  Pipelines and Other Transportation Assets. The costs of pipelines and other
transportation assets are depreciated using the straight-line method over the
estimated useful lives of the related assets.
 
  Syndication and Organization Costs. Costs and expenses incurred by Kelley
Partners in connection with syndication and organization have been charged to
partners' equity.
 
  Net Loss Per Unit. Net loss per Unit is computed based on the weighted
average number of Units outstanding during the period divided into the net
loss allocable to the Unitholders.
 
  Concentration of Credit Risk. Substantially all of Kelley Partners'
receivables are due from the marketing subsidiary of Kelley Oil, which
purchases natural gas for resale to a limited number of natural gas
transmission companies and other gas purchasers. See Note 8--Related Party
Transactions.
 
  Fair Value of Financial Instruments. The carrying value of cash, receivables
and accounts payable approximates their fair value. The fair value of
Convertible Subordinated Notes and Debentures are disclosed in Note 4--Equity
and Debt Offerings.
 
NOTE 2--DISTRIBUTION POLICY
 
  Net Available Cash. Prior to the Consolidation, the Partnership Agreement of
Kelley Partners required that cash distributions be no less than 75% of its
net available cash on a quarterly basis. For these purposes, net available
cash is generally defined as the net operating revenues of Kelley Partners and
Kelley Operating (determined on a combined basis) after payment of certain
expenses, including interest expenses, and after giving effect to such
reserves as Kelley Oil may determine to be required for the business of Kelley
Partners and Kelley Operating, but before repayment of principal or
development, acquisition and exploration costs. Net available cash is
determined for Kelley Partners and Kelley Operating on a combined basis as if
both were one entity and generally corresponds to the sum of net income (loss)
and exploration and dry hole costs plus depreciation, depletion and
amortization and other noncash charges. Net available cash is not intended to
correspond to net cash provided by operating activities computed under
generally accepted accounting principles.
 
                                     F-39
<PAGE>
 
                        KELLEY OIL & GAS PARTNERS, LTD.
 
      NOTES TO CONSOLIDATED AND INTERIM FINANCIAL STATEMENTS--(CONTINUED)

  Cash Distributions. The following table sets forth, for the periods
indicated, Kelley Partners' cash distributions per Unit. Cash distributions
were paid in the quarter indicated and relate to operations in the preceding
quarter.
 
<TABLE>
<CAPTION>
                                                                      1993  1994
                                                                      ----- ----
<S>                                                                   <C>   <C>
First quarter........................................................ $ .32 .30
Second quarter.......................................................   .30 .20
Third quarter........................................................   .30 .20
Fourth quarter.......................................................   .30 .07
                                                                      ----- ---
Totals............................................................... $1.22 .77
                                                                      ===== ===
</TABLE>
 
  Kelley Partners paid a quarterly distribution of $.02 per Unit on February
27, 1995 relating to operations in the fourth quarter of 1994. Following the
Consolidation, the Partnership Agreements of Kelley Partners and Kelley
Operating were amended to eliminate the distribution requirements.
 
NOTE 3--EXCHANGE OFFERS
 
  Development Partnerships. Kelley Partners has developed its proved
undeveloped reserves through its direct participation in development drilling
activities in conjunction with development drilling partnerships sponsored by
Kelley Oil ("DDPs"). Prior to the Consolidation, Unitholders owning 100 or
more Units in Kelley Partners could, at their option, participate directly in
DDPs through a special development privilege. On behalf of Kelley Partners,
Kelley Oil sponsored one DDP in each year from 1987 through 1992 (the "1987
DDP" through the "1992 DDP"), together with a DDP that commenced operations in
February 1994 (the "1994 DDP"). Kelley Partners receives a 20% reversionary
interest after payout of the DDPs in exchange for its assignment of drilling
rights to the DDPs.
 
  1990 DDP Exchange. In October 1993, Kelley Partners completed an exchange
offer for interests of investors and the general partners in the 1990 DDP. The
exchange value of the net assets of the 1990 DDP, as determined by Kelley Oil,
aggregated approximately $27.3 million as of July 1, 1993, the effective date
of the 1990 DDP Exchange, or $2.6665 for each unit in the 1990 DDP. The
exchange was accounted for using the purchase method. Effective July 1, 1993,
the results of operations of the 1990 DDP were included in the results of
operations of Kelley Partners. Pursuant to the 1990 DDP Exchange, Kelley
Partners incurred syndication expenses and assumed the liabilities of the 1990
DDP aggregating $11.3 million and acquired all of the oil and gas interests
and related assets of the 1990 DDP, effective as of July 1, 1993, in exchange
for 1.4 million Units in Kelley Partners, of which Kelley Oil received a total
of 1.0 million Units for its general partner interest and units in the 1990
DDP, and officers and directors of Kelley Oil received a total of 66,135 Units
in exchange for their units in the 1990 DDP.
 
  1991 DDP Exchange. In October 1994, Kelley Partners completed an exchange
offer for interests of investors and the general partners in the 1991 DDP. The
exchange value of the net assets of the 1991 DDP, as determined by Kelley Oil,
aggregated approximately $18.7 million as of July 1, 1994, the effective date
of the 1991 DDP Exchange, or $1.5696 for each unit in the 1991 DDP. The
exchange was accounted for using the purchase method. Effective July 1, 1994,
the results of operations of the 1991 DDP were included in the results of
operations of Kelley Partners. Pursuant to the 1991 DDP Exchange, Kelley
Partners incurred syndication expenses and assumed the liabilities of the 1991
DDP aggregating $8.1 million and acquired all of the oil and gas interests and
related assets of the 1991 DDP, effective as of July 1, 1994, in exchange for
2.5 million Units in Kelley Partners, of which Kelley Oil received a total of
1.8 million Units for its general partner interest and units in the 1991 DDP,
and officers and directors of Kelley Oil received a total of 69,450 Units in
exchange for their units in the 1991 DDP.
 
                                     F-40
<PAGE>
 
                        KELLEY OIL & GAS PARTNERS, LTD.
 
      NOTES TO CONSOLIDATED AND INTERIM FINANCIAL STATEMENTS--(CONTINUED)
 
  If the 1991 DDP Exchange had been effective as of January 1, 1994, revenues
would have increased on an unaudited pro forma basis to $39.0 million and net
loss, net loss allocable to limited partners, net loss allocable to general
partners and net loss per Unit would have decreased on an unaudited pro forma
basis to $42.2 million, $40.5 million and $1.7 million and $1.74,
respectively, for the year ended December 31, 1994. On an unaudited pro forma
basis after giving effect to the 1991 DDP Exchange for the year ended December
31, 1993, revenues, net loss, million, net loss allocable to limited partners,
net loss allocable to general partners and net loss per Unit would be $50.8
million, $29.5 million, $28.3 million $1.2 million and $1.41, respectively.
 
NOTE 4--EQUITY AND DEBT OFFERINGS
 
  1993 Unit Offering. In September 1993, Kelley Partners completed an
underwritten public offering of 3.0 million Units at a purchase price of
$15.75 per Unit, with an additional .3 million Units issued at the same price
upon exercise of the underwriters' overallotment option (the "Public
Offering"). Net proceeds from the Public Offering aggregated $47.3 million.
 
  Total Changes in Units Outstanding. The following table sets forth a summary
of changes in Units outstanding:
 
<TABLE>
      <S>                                                             <C>
      Units outstanding at January 1, 1993........................... 16,033,009
                                                                      ----------
      1990 DDP Exchange, effective July 1, 1993......................  1,443,845
      Public Offering, September 30 and October 12, 1993.............  3,285,000
      Note and debenture conversions.................................    102,560
                                                                      ----------
        Units outstanding at December 31, 1993....................... 20,864,414
                                                                      ----------
      Debenture conversions..........................................        476
      1991 DDP Exchange, effective July 1, 1994......................  2,486,755
                                                                      ----------
      Units outstanding at December 31, 1994......................... 23,351,645
                                                                      ==========
</TABLE>
 
  1990 Debenture Offering. On April 27, 1990, Kelley Partners completed an
underwritten public offering of its 8 1/2% Convertible Subordinated Debentures
due April 1, 2000 ("KLY 8 1/2% Debentures") in the aggregate principal amount
of $26.9 million. Prior to the Consolidation, the KLY 8 1/2% Debentures were
convertible into Units at a conversion rate of 42.533 Unit per $1,000
principal amount. To reflect the exchange ratios for the Units in the
Consolidation, the conversion feature of the KLY 8 1/2% Debentures was
adjusted to 51.864 shares of KOGC Common Stock per $1,000 principal amount or,
at the election of the holder, 25.932 shares of KOGC Common Stock and 5.411
shares of KOGC Preferred Stock per $1,000 principal amount. The KLY 8 1/2%
Debentures are redeemable upon the occurrence of specified events and are
subordinated in right of payment to the prior payment in full of all senior
debt of Kelley Partners. The estimated fair value of the KLY 8 1/2% Debentures
at December 31, 1994 was approximately $21.9 million based on their quoted
price on the American Stock Exchange.
 
  1992 Note Offering. On December 15, 1992, Kelley Partners completed an
underwritten public offering of its 7 7/8% Convertible Subordinated Notes due
1999 in the aggregate principal amount at maturity of $36.2 million (the "KLY
7 7/8% Notes"). The KLY 7 7/8% Notes were offered at an original issue
discount of 17.11% and were convertible into Units prior to the Consolidation
at the rate of 58.470 Units per $1,000 face amount of KLY 7 7/8% Notes. The
conversion rate is subject to antidilution adjustments upon certain events,
including distributions on Units during any twelve-month period, commencing
October 1, 1992, in an aggregate amount exceeding Kelley Partners' total net
available cash for that period. The conversion rate of the KLY 7 7/8% Notes
was increased under their antidilution provisions to account for distributions
in excess of net available cash for that period. To reflect the exchange
ratios for the Units in the Consolidation, the conversion feature of the KLY
 
                                     F-41
<PAGE>
 
                        KELLEY OIL & GAS PARTNERS, LTD.
 
      NOTES TO CONSOLIDATED AND INTERIM FINANCIAL STATEMENTS--(CONTINUED)

7 7/8% Notes was adjusted to 71.263 shares of KOGC Common Stock per $1,000
face amount or, at the election of the holder, 35.632 shares of KOGC Common
Stock and 7.435 shares of KOGC Preferred Stock per $1,000 face amount.
 
  The KLY 7 7/8% Notes may not be called for redemption by Kelley Partners
prior to maturity but are redeemable at the option of the holders under
certain events involving a change of control in Kelley Partners. The KLY 7
7/8% Notes rank equally with the KLY 8 1/2% Debentures and are subordinated in
right of payment to the prior payment in full of all senior debt of Kelley
Partners. Net proceeds from the KLY 7 7/8% Note offering were $28.2 million.
The estimated fair value of the KLY 7 7/8% Notes at December 31, 1994 was
approximately $30.9 million based on a comparison to the market value of the
KLY 8 1/2% Debentures, adjusted for differences in interest rates, maturity
and discount factors.
 
NOTE 5--PIPELINE OPERATIONS
 
  Kelley Partners owns certain natural gas pipeline facilities in Louisiana
(the "Pipeline Facilities"). Under a contract with the City of Lafayette,
Kelley Partners received facilities fees prior to May 1993 equal to the direct
construction costs of the portion of the Pipeline Facilities serving an
electrical generating plant owned by the City. These fees aggregated
approximately $.6 million in 1992 and $.3 million in 1993. After May 1993,
transportation charges were billed to the City at a level based on a rate of
return on the depreciated pipeline cost.
 
NOTE 6--BUSINESS SEGMENTS
 
  During 1993 and 1994, Kelley Partners' business segments conducted the
following activities:
 
  Oil and gas--domestic oil and gas producing activities
 
  Gas transmission--purchase, sale and transportation of natural gas
 
                                (IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                                                      DEPRECIATION
                                  OPERATING                            DEPLETION
                                   INCOME   IDENTIFIABLE   CAPITAL        AND
                         REVENUES (LOSS)(1)    ASSETS    EXPENDITURES AMORTIZATION
                         -------- --------- ------------ ------------ ------------
<S>                      <C>      <C>       <C>          <C>          <C>
December 31, 1993
 (RESTATED):
  Oil and gas........... $33,977   (21,569)   177,580       62,854       29,966
  Gas transmission......   3,781      (207)     6,546        1,316          486
  Other.................      62        --         --           --           --
                         -------   -------    -------       ------       ------
  Consolidated.......... $37,820   (21,776)   184,126       64,170       30,452
                         =======   =======    =======       ======       ======
December 31, 1994:
  Oil and gas........... $30,710   (29,659)   200,142       61,655       37,325
  Gas transmission......   3,819      (540)     5,372          (52)         526
  Other.................     219        --         --           --           --
                         -------   -------    -------       ------       ------
  Consolidated.......... $34,748   (30,199)   205,514       61,603       37,851
                         =======   =======    =======       ======       ======
</TABLE>
--------
(1) Operating income (loss), which approximates gross profit, is computed as
    operating revenues less cost of gas sold, lease operating expenses,
    severance taxes, exploration and dry hole costs and depreciation,
    depletion and amortization.
 
                                     F-42
<PAGE>
 
                        KELLEY OIL & GAS PARTNERS, LTD.
 
      NOTES TO CONSOLIDATED AND INTERIM FINANCIAL STATEMENTS--(CONTINUED)
 
  Intersegment revenue, which has been eliminated, is comprised of interest
aggregating $.2 million and $0 and oil and gas sales to affiliates aggregating
$27.6 million and $24.2 million for the years ended December 31, 1993 and
1994, respectively. See Note 8--Related Party Transactions.
 
  Oil and gas revenues include $.3 million and $.1 million in 1993 and 1994,
respectively, for rebates related to a settlement with a gas purchaser.
 
NOTE 7--NOTES PAYABLE
 
  Credit Facilities. Prior to the Consolidation, Kelley Partners and Kelley
Operating were parties to a credit agreement with Bank of Montreal, as agent
for participating banks, providing for a revolving credit/term loan facility
of up to $75 million (the "Prior Credit Facility"). Borrowings under the Prior
Credit Facility were limited to a borrowing base increased to $70 million in
December 1994. Interest was payable on borrowings under the Prior Credit
Facility at a floating rate equal to 1/2% above the bank's prime rate or, at
the election of Kelley Partners, 2% above a quoted Libor rate, together with a
commitment fee of 1/2% per annum of the unused portion of the borrowing base.
The credit agreement provided for payments of interest only until the
scheduled conversion date of July 1, 1995, when any borrowings under the Prior
Credit Facility in excess of 25% of the prevailing borrowing base were
scheduled to be repaid and the balance of the facility converted into a term
loan payable over four years in equal quarterly installments. Kelley Partners
obtained advances under the Prior Credit Facility aggregating $46.9 million
during 1994 primarily for financing its ongoing lease acquisition and drilling
activities. As of December 31, 1994, $69.9 million was outstanding under the
Prior Credit Facility.
 
  In connection with the Consolidation, KOGC completed a refinancing for the
outstanding bank debt of Kelley Partners and Kelley Oil. The refinancing was
provided by Kelley Partners' prior lending banks under a $70 million revolving
credit facility (the "Credit Facility") and a $20 million term loan facility
(the "Term Facility"). The borrowers under the facilities are Kelley Operating
and Kelley Oil. Kelley Partners, KOGC and its other subsidiary partnerships
are guarantors. Borrowings of $90 million under the two facilities were used
to refinance Kelley Partners' bank debt of $69.9 million, Kelley Oil's bank
debt of $9 million and borrowings of $6 million by the 1992 DDP, with the
balance of $5.1 million used to fund payables of Kelley Partners and KOGC,
including part of the expenses for the Consolidation. Borrowings under the
Credit Facility were reduced by $10 million in February 1995 from part of the
proceeds of an equity private placement by KOGC.
 
  Interest is payable on borrowings under the Credit Facility at a floating
rate equal to 1/2% above the agent bank's prime rate or, at the election of
Kelley Partners, 2 1/2% above a quoted Libor rate, together with a commitment
fee of 5/8% per annum of the unused portion of the borrowing base, which is
subject to adjustments based on semiannual evaluations of the KOGC's oil and
gas reserves. The agreement for the Credit Facility requires the payment of
interest only until January 1, 1997, when all borrowings under the facility
will be repayable, subject to annual extensions at the lenders' discretion if
all borrowings under the Term Facility have been repaid. The Term Facility is
amortizable 10% on July 31, 1995 and 15% every three months thereafter, with a
final payment due on January 31, 1997, subject to prepayment from proceeds of
any equity offering after February 9, 1995. Interest is payable on borrowings
under the Term Facility at a floating rate equal to 3 1/2% above the agent
bank's prime rate, increased by 1% every six months after the closing.
 
  Borrowings under the Credit Facility and Term Facility are prepayable
without penalty or premium and are secured by mortgages on all of the oil and
gas and pipeline assets of Kelley Partners, Kelley Operating, KOGC and its
subsidiaries, together with a security interest in production proceeds from
oil and gas sales. The agreements covering the facilities require the consent
of the lenders for third-party borrowings or extraordinary transactions and
provide financial covenants of KOGC including a restriction on total funded
debt to capital of .7 to 1.0, a minimum fixed charge coverage ratio of 1.25 to
1.0, a minimum interest coverage ratio of 2.35 to 1.0, current ratio of 1.0 to
1.0 and restrictions on capital expenditures under specified circumstances.
 
                                     F-43
<PAGE>
 
                        KELLEY OIL & GAS PARTNERS, LTD.
 
      NOTES TO CONSOLIDATED AND INTERIM FINANCIAL STATEMENTS--(CONTINUED)
 
  Aggregate Maturities. Assuming that the scheduled January 31, 1997 maturity
date for the Credit Facility is not extended, aggregate maturities of the
Credit Facility, Term Facility, the KLY 8 1/2% Debentures and the KLY 7 7/8%
Notes for the next five years and thereafter, after giving effect to the
Consolidation, are as follows: $4.4 million in 1995, $10.6 million in 1996,
$54.8 million in 1997, $0 in 1998, $34.4 million in 1999 and $26.9 million
thereafter. See Note 4--Equity and Debt Offerings.
 
  Interest Payments. Interest paid during the years ended December 31, 1992,
1993 and 1994 aggregated $3.3 million, $6.6 million and $8.2 million,
respectively.
 
NOTE 8--RELATED PARTY TRANSACTIONS
 
  Reimbursements. Kelley Oil is reimbursed for its direct costs and an
allocable portion of its general and administrative expenses incurred as
managing general partner of Kelley Partners.
 
  Advances to Affiliated DDPs. Kelley Partners advanced approximately $1.9
million to the 1994 DDP, $1.2 million to the 1992 DDP and $.6 million to the
1991 DDP prior to the closings of their respective offerings to fund
syndication costs and drilling activities. The entire amounts were repaid with
interest at a market rate following the closings of the offerings.
 
  Sales to Affiliates. Substantially all gas produced by Kelley Partners and
the DDPs (collectively, the "Kelley Group") is covered by gas marketing
agreements with Concorde Gas Marketing, Inc., an indirect wholly owned
subsidiary of Kelley Oil ("CGM"). Under the agreements, CGM is responsible for
purchasing gas for resale, administering gas sales, marketing gas not taken by
purchasers under gas purchase contracts and performing related services,
including gas transportation arrangements, oversight of gas gathering
operations, revenue receipt and disbursement functions, administrative
filings, recordkeeping and inspection, testing and monitoring functions.
During 1994, CGM received from the Kelley Group and unrelated customers either
fees or a marketing differential at the rate of $.05 per MMBTU of gas sold and
delivered under these arrangements. For 1995, the marketing fee was modified
to 2% of the resale price for marketed natural gas. The Company believes that
similar arrangements are customary among natural gas producers and their
marketing affiliates. For the years ended December 31, 1993 and 1994, sales to
CGM under the agreements were $27.6 million and $24.2 million, respectively,
and CGM earned total fees on marketing differentials from the Kelley Group of
$1.1 million and $1.6 million in 1993 and 1994, respectively. See Note 9--
Sales to Major Customers.
 
  Purchases from Affiliates. Gas purchases from the Kelley Group for resale
through Lafayette Gas Intrastate, a joint venture through which Kelley
Partners owns the Pipeline Facilities, were approximately $3.3 million and
$3.6 million for the years ended December 31, 1993 and 1994, respectively.
 
  Direct Costs and Allocated Overhead. Overhead allocated to Kelley Partners
by Kelley Oil relating to general and administrative expenses for the years
ended December 31, 1993 and 1994 were $2.0 million and $2.0 million,
respectively.
 
  Kelley Oil is reimbursed by Kelley Partners for direct costs incurred and
advanced in connection with financings and acquisitions by Kelley Partners.
These reimbursements aggregated $.6 million for Kelley Partners' share of
Consolidation expenses, $.3 million for the 1991 DDP Exchange, $.6 million for
the 1993 Public Offering, $1.1 million for the 1990 DDP Exchange, and $.3
million for the Note offering.
 
  Kelley Oil has also been reimbursed for costs directly associated with lease
acquisition, exploration and development activities. These costs aggregated
$4.5 million and $5.3 million for the years ended December 31, 1993 and 1994,
respectively. Kelley Partners capitalized $1.9 million and $1.9 million of
allocated direct costs to oil and gas properties for the years ended December
31, 1993 and 1994, respectively.
 
                                     F-44
<PAGE>
 
                        KELLEY OIL & GAS PARTNERS, LTD.
 
      NOTES TO CONSOLIDATED AND INTERIM FINANCIAL STATEMENTS--(CONTINUED)
 
  An indirect wholly owned subsidiary of Kelley Oil was reimbursed
approximately $.1 million in each of 1993 and 1994 for its direct costs in
managing the Pipeline Facilities. See Note 5--Pipeline Operations.
 
NOTE 9--SALES TO MAJOR CUSTOMERS
 
  Sales to customers in excess of 10% of total oil and gas sales are as
follows:
 
                                (IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                                            YEARS ENDED
                                                           DECEMBER 31,
                                                         -------------------
                                                            1993       1994
                                                         ----------   ------
                                                         (RESTATED)
<S>                                                      <C>          <C>
Concorde Gas Marketing..................................  $27,618(1)  24,242(1)
Falco S & D Inc.........................................    4,125      4,330
</TABLE>
--------
(1) During 1993 and 1994, CGM purchased approximately 20% and 22%,
    respectively, of its total oil and gas purchases for resale to LIG
    Chemical Company. Other customers accounting for 10% or more of CGM's
    resales during 1993 and 1994 were Pontchartrain Natural Gas System (24%
    and 23%, respectively), Fina Natural Gas Company (13% and 10%,
    respectively), and during 1994, Associated Natural Gas Inc. (18%).
 
NOTE 10--HEDGING ACTIVITIES
 
  The Partnership's production is sold on its behalf principally by Kelley
Oil, which periodically uses forward sales contracts and derivative financial
instruments covering natural gas to reduce exposure to downward price
fluctuations on natural gas production. As of December 31, 1994, through a
combination of natural gas swap agreements and forward sales contracts,
between 20% and 50% of anticipated natural gas production for the first nine
months of 1995 was hedged at prices above prevailing futures prices for each
contract month. Subsequent arrangements were made at similar prices for
approximately 50% of anticipated natural gas production for the full year. The
natural gas swap agreements generally provide for the Partnership to receive
or make counterparty payments on the differential between a fixed price and a
variable indexed price for natural gas. No significant realized gains or
losses were deferred at December 31, 1994. The Partnership did not have any
hedged positions at December 31, 1993.
 
  The credit risk exposure from counterparty nonperformance on natural gas
forward sales contracts and derivative financial instruments is generally the
amount of unrealized gains under the contracts. The Partnership has not
experienced counterparty nonperformance on these agreements and does not
anticipate any in future periods.
 
NOTE 11--INTERIM PRESENTATION
 
  General. The accompanying consolidated financial statements of Kelley Oil &
Gas Partners, Ltd. ("Kelley Partners" or the "Partnership") have been prepared
in accordance with generally accepted accounting principles and, in the
opinion of management, reflect all adjustments (consisting of normal recurring
adjustments) necessary for a fair statement of the results for the interim
periods presented. The accounting policies followed by the Partnership are set
forth in Note 1 to Kelley Partners' audited financial statements included
elsewhere in this Prospectus.
 
  Consolidation. On February 7, 1995, ownership of the equity interests in
Kelley Partners and Kelley Oil Corporation, its managing general partner
("Kelley Oil"), was consolidated (the "Consolidation") into Kelley Oil & Gas
Corporation ("KOGC"). In the Consolidation, Units in Kelley Partners held by
investors other than Kelley Oil and its subsidiaries (the "Public
Unitholders") were converted into common and preferred stock of
 
                                     F-45
<PAGE>
 
                        KELLEY OIL & GAS PARTNERS, LTD.
 
      NOTES TO CONSOLIDATED AND INTERIM FINANCIAL STATEMENTS--(CONTINUED)

KOGC, and Kelley Partners became a 99.98% owned subsidiary partnership of
KOGC. Following the Consolidation, the historical carrying values of Kelley
Partners' oil and gas properties and publicly held subordinated debt were
adjusted to conform with KOGC's cost basis for those assets and liabilities in
the Consolidation, reflecting their estimated fair market values at February
7, 1995 based on the market value of the common and preferred stock issued to
the Public Unitholders.
 
  As a result of this accounting approach, commonly referred to as "pushdown
accounting," the following adjustments were made to reflect Kelley Partners'
assets and liabilities at fair market value and the net effect on limited
partners' equity at February 7, 1995:
 
                                (IN THOUSANDS)
 
<TABLE>
   <S>                                                                 <C>
   Increase (decrease) in:
     Purchased unproved properties.................................... $ 85,182
     Properties subject to amortization............................... (225,698)
     Pipelines and other transportation assets........................   (4,274)
     Accumulated depreciation, depletion and amortization............. (195,405)
     Convertible subordinated debentures..............................   (5,103)
     Convertible subordinated notes...................................   (5,110)
     Limited partners' equity.........................................   60,828
</TABLE>
 
  If the Consolidation had not taken place, Kelley Partners' depletion,
depreciation and amortization for the quarter ended March 31, 1995 would have
increased by approximately $1.9 million, with a corresponding increase in its
net loss for the quarter.
 
  Change to Successful Efforts Accounting Method. During the third quarter of
1994, Kelley Partners changed from the full cost method to the successful
efforts method of accounting for its oil and gas operations. As a result of
the change in accounting method, Kelley Partners' previously reported net loss
of $.9 million for the quarter ended March 31, 1994 has been restated to a net
loss of $6.8 million.
 
 
                                     F-46
<PAGE>
 
                        KELLEY OIL & GAS PARTNERS, LTD.
 
      NOTES TO CONSOLIDATED AND INTERIM FINANCIAL STATEMENTS--(CONTINUED)
 
NOTE 12--SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND GAS EXPLORATION,
        DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)
 
  This section provides information required by Statement of Financial
Accounting Standards No. 69, "Disclosures about Oil and Gas Producing
Activities."
 
  Capitalized costs and accumulated depreciation, depletion and amortization
relating to oil and gas producing activities, all of which are conducted within
the continental United States, are summarized below.
 
                                 (IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                                               YEARS ENDED
                                                              DECEMBER 31,
                                                           -------------------
                                                              1993      1994
                                                           ---------- --------
                                                           (RESTATED)
<S>                                                        <C>        <C>
Unevaluated properties....................................  $  8,168     7,199
Evaluated properties subject to amortization..............   312,434   375,058
                                                            --------  --------
Capitalized costs.........................................   320,602   382,257
Accumulated depreciation, depletion and amortization......  (151,669) (189,454)
                                                            --------  --------
Net capitalized costs.....................................  $168,933   192,803
                                                            ========  ========
</TABLE>
 
  Costs incurred in oil and gas acquisition, exploration and development
activities are summarized below.
 
                                 (IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                                                  YEARS ENDED
                                                                 DECEMBER 31,
                                                               -----------------
                                                                  1993     1994
                                                               ---------- ------
                                                               (RESTATED)
<S>                                                            <C>        <C>
Property acquisition costs:(1)
  Proved......................................................  $35,247   41,994
  Unproved....................................................    1,310    1,850
Exploration costs.............................................   14,208    4,522
Development costs.............................................   27,494   26,001
                                                                -------   ------
  Total costs incurred........................................  $78,259   74,367
                                                                =======   ======
</TABLE>
--------
(1) Includes assets acquired through exchange offers aggregating $34.9 million
    and $24.2 million for years ended December 31, 1993 and 1994, respectively.
 
                                      F-47
<PAGE>
 
                        KELLEY OIL & GAS PARTNERS, LTD.
 
      NOTES TO CONSOLIDATED AND INTERIM FINANCIAL STATEMENTS--(CONTINUED)
 
  Results of operations for oil and gas producing activities are summarized
below.
 
                                (IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                                                YEARS ENDED
                                                                DECEMBER 31,
                                                             ------------------
                                                                1993     1994
                                                             ---------- -------
                                                             (RESTATED)
<S>                                                          <C>        <C>
Oil and gas revenues........................................  $ 33,977   30,710
Production costs............................................   (10,175) (10,332)
Exploration and dry hole costs..............................   (15,404) (12,712)
Depreciation, depletion and amortization....................   (29,960) (37,325)
                                                              --------  -------
Results of operations.......................................  $(21,562) (29,659)
                                                              ========  =======
</TABLE>
 
  Results of operations from oil and gas producing activities are determined
using actual historical revenues, production costs (including production
related taxes), exploration and dry hole costs and depreciation, depletion and
amortization of the capitalized costs subject to amortization. General and
administrative expenses and interest expense are excluded from this
determination of results of operations.
 
  Kelley Partners' 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, are summarized below.
 
<TABLE>
<CAPTION>
                                    CRUDE OIL, CONDENSATE
                                   AND NATURAL GAS LIQUIDS      NATURAL GAS
                                           (MBBLS)                (MMCF)
                                   -------------------------  ----------------
                                       1993         1994       1993     1994
                                   ------------  -----------  -------  -------
<S>                                <C>           <C>          <C>      <C>
Proved developed and undeveloped
 reserves:
  Beginning of year...............        2,681        1,861  173,324  149,817
  Minerals in place received in
   DDP Exchanges..................          492          345   17,439    9,236
  Purchases of reserves in place..           --           52       --   11,463
  Revisions of previous
   estimates......................       (1,478)         149  (58,261)  (7,628)
  Extensions and discoveries......          456          145   31,043   11,644
  Production......................         (290)        (331) (13,728) (13,777)
                                   ------------  -----------  -------  -------
  End of year.....................        1,861        2,221  149,817  160,755
                                   ============  ===========  =======  =======
Proved developed reserves at end
 of year..........................        1,351        1,546  100,090  106,467
                                   ============  ===========  =======  =======
</TABLE>
 
                                     F-48
<PAGE>
 
                        KELLEY OIL & GAS PARTNERS, LTD.
 
      NOTES TO CONSOLIDATED AND INTERIM FINANCIAL STATEMENTS--(CONTINUED)
 
  The table of the Standardized Measure of Discounted Future Net Cash Flows
relating to Kelley Partners' ownership interests in proved oil and gas
reserves as of year end is shown below.
 
                                (IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                                               YEARS ENDED
                                                               DECEMBER 31,
                                                             -----------------
                                                               1993     1994
                                                             --------  -------
<S>                                                          <C>       <C>
Future cash inflows......................................... $385,520  295,374
Future production costs.....................................  (67,241) (67,923)
Future development costs....................................  (35,345) (34,333)
                                                             --------  -------
Future net cash flows.......................................  282,934  193,118
10% annual discount for estimating timing of cash flows..... (135,679) (78,106)
                                                             --------  -------
Standardized measure of discounted future net cash flows.... $147,255  115,012
                                                             ========  =======
</TABLE>
 
  Future cash inflows are computed by applying year-end prices of oil and gas
to year-end quantities of proved oil and gas reserves. Future production and
development costs are computed by Kelley Oil's petroleum engineers by
estimating the expenditures to be incurred in developing and producing Kelley
Partners' proved oil and gas reserves at the end of the year, based on year-
end costs and assuming continuation of existing economic conditions.
 
  A discount factor of 10% was used to reflect the timing of future net cash
flows. The standardized measure of discounted future net cash flows is not
intended to represent the replacement cost or fair market value of Kelley
Partners' oil and gas properties.
 
  The standardized measure of discounted future net cash flows as of December
31, 1993 and 1994 was calculated using prices in effect as of those dates,
which averaged $13.80 and $15.65, respectively, per barrel of oil and $2.40
and $1.62, respectively, per Mcf of natural gas.
 
                                     F-49
<PAGE>
 
                        KELLEY OIL & GAS PARTNERS, LTD.
 
      NOTES TO CONSOLIDATED AND INTERIM FINANCIAL STATEMENTS--(CONTINUED)
 
  Changes in standardized measure of future net cash flows relating to proved
oil and gas reserves are summarized below.
 
                                (IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                                               YEARS ENDED
                                                               DECEMBER 31,
                                                             -----------------
                                                               1993     1994
                                                             --------  -------
<S>                                                          <C>       <C>
Changes due to current year operations:
  Sales of oil and gas, net of production costs............. $(23,802) (20,378)
  Extensions and discoveries................................   27,565    9,803
  Minerals in place received in DDP Exchanges, net of future
   development and production costs.........................   30,331   18,699
  Purchases of reserves in place............................       --   10,074
  Development costs incurred during the year................   15,162    8,709
Changes due to revisions in standardized variables:
  Prices and production costs...............................   (4,357) (48,334)
  Revisions of previous quantity estimates..................  (95,042) (14,897)
  Estimated future development costs........................   (3,217) (10,922)
Accretion of discount.......................................   20,073   14,725
Production rates (timing) and other.........................  (20,188)     278
                                                             --------  -------
Net increase (decrease).....................................  (53,475) (32,243)
Beginning of year...........................................  200,730  147,255
                                                             --------  -------
End of year................................................. $147,255  115,012
                                                             ========  =======
</TABLE>
 
  Sales of oil and gas, net of production costs, are based on historical
results. Extensions and discoveries, minerals in place received in exchange
offers, purchases of reserves in place, the changes due to revisions in
standardized variables and the accretion of discount are reported on a
discounted basis. Revisions of previous quantity estimates include reductions
in proved undeveloped reserves attributable to drill sites assigned to DDPs.
 
 
                                     F-50
<PAGE>
 
                       SELECTED QUARTERLY FINANCIAL DATA
 
                                  (UNAUDITED)
 
                     (IN THOUSANDS, EXCEPT PER UNIT DATA)
 
<TABLE>
<CAPTION>
                                                 QUARTER ENDED
                                ------------------------------------------------
                                MARCH 31,   JUNE 30,  SEPTEMBER 30, DECEMBER 31,
                                   1993       1993        1993          1993
                                ---------- ---------- ------------- ------------
                                (RESTATED) (RESTATED)  (RESTATED)    (RESTATED)
<S>                             <C>        <C>        <C>           <C>
Operating revenues.............   $8,275     $9,650      $9,742       $10,091
Operating loss(1)..............     (799)    (1,567)     (5,994)      (13,416)
Net loss.......................   (3,283)    (4,142)     (8,833)      (15,933)
Net loss per unit..............     (.20)      (.25)       (.48)         (.73)
</TABLE>
 
<TABLE>
<CAPTION>
                                                 QUARTER ENDED
                                ------------------------------------------------
                                MARCH 31,   JUNE 30,  SEPTEMBER 30, DECEMBER 31,
                                   1994       1994        1994          1994
                                ---------- ---------- ------------- ------------
                                (RESTATED) (RESTATED)
<S>                             <C>        <C>        <C>           <C>
Operating revenues.............   $9,983    $ 7,892      $ 8,661      $ 7,993
Operating loss(1)..............   (4,209)    (7,215)      (9,300)      (9,475)
Net loss.......................   (6,803)   (10,056)     (12,354)     (13,401)
Net loss per unit..............     (.31)      (.46)        (.51)        (.55)
</TABLE>
--------
(1) Operating income (loss), which approximates gross profit, is computed as
    operating revenues less cost of gas sold, lease operating expenses,
    severance taxes, exploration and dry hole costs and depreciation,
    depletion and amortization.
 
                                     F-51
<PAGE>
 
 
                       [LOGO OF KELLEY OIL APPEARS HERE]
 
<PAGE>
 
                                    PART II
 
                  INFORMATION NOT REQUIRED IN THE PROSPECTUS
 
ITEM 20. INDEMNIFICATION OF DIRECTORS AND OFFICERS
 
  Article VI of the Bylaws of Kelley Oil & Gas Corporation (the "Company")
provides for the Company's indemnification of officers, directors and
controlling persons to the full extent provided in the General Corporation Law
of Delaware (the "GCL"). Section 145 of the GCL provides that a corporation
may indemnify any person who was or is a party or is threatened to be made a
party to any threatened, pending or completed proceeding (other than a
proceeding by or in the right of the corporation) by reason of the fact that
he is or was a director, officer, employee or agent of the corporation, or is
or was serving at the request of the corporation in a similar position with
another entity, against expenses (including attorneys' fees), judgments, fines
and settlements incurred by him in connection with the proceeding if he acted
in good faith and in a manner reasonably believed to be in or not opposed to
the best interests of the corporation, and with respect to any criminal action
or proceeding, had no reasonable cause to believe his conduct was unlawful.
Indemnification under Section 145 of the GCL is limited in a proceeding by or
in the right of the corporation to expenses (including attorneys' fees)
incurred in connection with the proceeding. In either case, no indemnification
shall be made if the indemnified person has been adjudged to be liable for
negligence or misconduct in the performance of this duty to the corporation,
unless, and to the extent the Delaware court of Chancery or other court in
which the proceeding was brought, despite the adjudication of liability
determines such person is entitled to indemnity.
 
  Section 145 of the GCL provides that the indemnity obligations of a
corporation shall only arise if authorized by (i) a majority of a quorum of
directors who are not a party to the proceeding, (ii) independent legal
counsel to the corporation if a quorum of directors is not obtainable, (iii)
independent legal counsel to the corporation if a quorum if directors is
obtainable and the directors direct counsel to make the determination or (iv)
the stockholders. The board of directors of the corporation may authorize
expenses in connection with a proceeding to be paid in advance of the final
disposition upon receipt of an undertaking by the person on whose behalf the
expenses are to be paid to repay the expenses in the event he is not entitled
to indemnity.
 
  Pursuant to Section 102(b) of the GCL, the Certificate of Incorporation of
the Company provides that a director of the Company shall not be personally
liable to the Company or its stockholders for monetary damages for a breach of
fiduciary duty as a director, except for liability (i) for any breach of the
director's duty of loyalty to the Company or its stockholders, (ii) for acts
or omissions not in good faith or which involved intentional misconduct or a
knowing violation of law, (iii) in connection with certain illegal dividend
payments and stock redemptions or (iv) for any transaction from which the
director derived an improver personal benefit.
 
  Delaware corporations also are authorized under the GCL to obtain insurance
to protect officers and directors from certain liabilities, including
liabilities against which the corporation cannot indemnify its directors and
officers. The Company currently has no directors' and officers' liability
insurance in effect.
 
ITEM 21. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
 
 (A) EXHIBITS.
 
  The following exhibits are filed herewith unless otherwise indicated:
 
<TABLE>
<CAPTION>
 EXHIBIT
 NUMBER: EXHIBIT
 ------- -------
 <C>     <S>
 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).
</TABLE>
 
                                     II-1
<PAGE>
 
<TABLE>
<CAPTION>
 EXHIBIT
 NUMBER: EXHIBIT
 ------- -------
 <C>     <S>
  3.2    Certificate of Amendment to Certificate of Incorporation of the
         Registrant dated December 20, 1994 (incorporated by reference to
         Exhibit 3.2 to the Consolidation Registration Statement).
  3.3    Certificate of Correction to Certificate of Incorporation of the
         Registrant dated February 12, 1996 (incorporated by reference to
         Exhibit 3.1 to the Registrant's Current Report on Form 8-K (File
         No. 0-25214) dated February 15, 1996).
  3.4    Certificate of Designation of $2.625 Convertible Exchangeable
         Preferred Stock of the Registrant (incorporated by reference to
         Exhibit 3.1 to the Registrant's Current Report on Form 8-K (File
         No. 0-25214) dated February 10, 1995).
  3.5    Certificate of Designations of Cumulative Convertible Preferred Stock
         of the Registrant (incorporated by reference to Exhibit 3.2 to the
         Registrant's Current Report on Form 8-K (File No. 0-25214) dated
         February 10, 1995).
  3.6    Bylaws of the Registrant (incorporated by reference to Exhibit 3.5 to
         the Consolidation Registration Statement).
  4.1    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).
  4.2    Registration Agreement, dated October 25, 1996, between the Registrant
         and Morgan Stanley & Co. Incorporated, for itself and the other
         several Purchasers named therein (incorporated by reference to Exhibit
         4.2 to the Registrant's Quarterly Report on Form 10-Q (File No. 0-
         25214) for the quarterly period ended September 30, 1996).
  4.3    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.
  4.4    Form of the Registrant's 10 3/8% Senior Subordinated Note Due 2006,
         Series A (incorporated by reference to Exhibit 4.4 to the Registrant's
         Quarterly Report on Form 10-Q (File No. 0-25214) for the quarterly
         period ended September 30, 1996).
 *4.5    Form of the Registrant's 10 3/8% Senior Subordinated Note Due 2006,
         Series B.
  4.6    Certificate representing Common Stock of the Registrant (incorporated
         by reference to Exhibit 4.1 to the Consolidation Registration
         Statement).
  4.7    Certificate representing $2.625 Convertible Exchangeable Preferred
         Stock of the Registrant (incorporated by reference to Exhibit 4.2 to
         the Consolidation Registration Statement).
  4.8    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).
  4.9    Supplemental Indenture dated March 29, 1996 between the Registrant and
         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).
</TABLE>
 
                                      II-2
<PAGE>
 
<TABLE>
<CAPTION>
 EXHIBIT
 NUMBER: EXHIBIT
 ------- -------
 <C>     <S>
   4.10  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).
   4.11  Supplemental Indenture dated March 29, 1996 between the Registrant and
         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).
   4.12  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).
   4.13  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 30, 1996).
   4.14  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).
  *5.1   Opinion of Fulbright & Jaworski L.L.P. regarding the legality of the
         Exchange Notes.
  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 10-K (File No. 0-175850 for the year ended December 31, 1991).
  10.4   1995 Incentive Stock Option Plan of the Registrant (the "1995 Plan")
         (incorporated by reference to Exhibit 10.4 to the Registrant's Annual
         Report on Form 10-K (File No. 0-25214) for the year ended December 31,
         1995.
  10.5   Amendment to the 1987 Plan, 1991 Plan and 1995 Plan (incorporated by
         reference to Exhibit 10.5 to the Registrant's Current Report on Form
         8-K (File No. 0-25214) dated February 15, 1996).
  10.6   1996 Nonqualified Stock Option Plan of the Registrant (incorporated by
         reference to Exhibit 10.4 to the Registrant's Current Report on Form
         8-K (File No. 0-25214) dated February 15, 1996).
  10.7   Employment Agreement dated as of February 15, 1996 between the
         Registrant and John F. Bookout, Jr. (incorporated by reference to
         Exhibit 10.2 to the Registrant's Current Report on Form 8-K
         (File No. 0-25214) dated February 15, 1996).
  10.8   Form of Employment Agreements dated as of February 15, 1996 between
         the Registrant and each of Dallas Laumbach, William Rankin 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).
 *12.1   Statement of Computation of Ratio of Earnings to Fixed Charges.
  21.1   Subsidiaries of the Registrant (incorporated by reference to the
         Registrant's Quarterly Report on
         Form 10-Q (File No. 0-17585) for the quarter ended September 30,
         1991).
</TABLE>
 
                                      II-3
<PAGE>
 
<TABLE>
<CAPTION>
 EXHIBIT
 NUMBER: EXHIBIT
 ------- -------
 <C>     <S>
  23.1   Consent of Deloitte & Touche LLP.
  23.2   Consent of Ernst &Young LLP.
 *23.3   Consent of Fulbright & Jaworski L.L.P. (included in Exhibit 5.1)
  23.4   Consent of H.J. Gruy & Associates, Inc.
  24.1   Powers of Attorney (included on page II-6).
  25.1   Statement of Eligibility Under Trust Indenture Act of 1939 of a
         Corporation Designated to Act as Trustee on Form T-1.
  99.1   Form of Letter of Transmittal and related documents.
</TABLE>
-------
* To be filed by amendment.
 
 (B) FINANCIAL STATEMENT SCHEDULES.
 
ITEM 22. UNDERTAKINGS
 
  The undersigned registrant hereby undertakes that, for purposes of
determining any liability under the Securities Act, each filing of the
registrant's annual report pursuant to section 13(a) or section 15(d) of the
Exchange Act (and, where applicable, each filing of an employee benefit plan's
annual report pursuant to section 15(d) of the Exchange Act) that is
incorporated by reference in the registration statement shall be deemed to be
a new registration statement relating to the securities offered therein, and
the offering of such securities at that time shall be deemed to be the initial
bona fide offering thereof.
 
  Insofar as indemnification for liabilities arising under the Securities Act
may be permitted to directors, officers and controlling persons of the
registrant pursuant to the foregoing provisions, or otherwise, the registrant
has been advised that in the opinion of the Securities and Exchange Commission
such indemnification is against public policy as expressed in the Securities
Act and is, therefore, unenforceable. In the event that a claim for
indemnification against such liabilities (other than the payment by the
registrant of expenses incurred or paid by a director, officer or controlling
person of the registrant in the successful defense of any action, suit or
proceeding) is asserted by such director, officer or controlling person in
connection with the securities being registered, the registrant will, unless in
the opinion of its counsel the matter has been settled by controlling precedent,
submit to a court of appropriate jurisdiction the question whether such
indemnification by it is against public policy as expressed in the Securities
Act and will be governed by the final adjudication of such issue.
 
  The undersigned registrant hereby undertakes to respond to requests for
information that is incorporated by reference into the prospectus pursuant to
Items 4, 10(b), 11, or 13 of this Form, within one business day of receipt of
such request, and to send the incorporated documents by first class mail or
other equally prompt means. This includes information contained in documents
filed subsequent to the effective date of the registration statement through
the date of responding to the request.
 
  The undersigned registrant hereby undertakes to supply by means of a post-
effective amendment all information concerning a transaction, and the company
being acquired involved therein, that was not the subject of and included in
the registration statement when it became effective.
 
                                     II-4
<PAGE>
 
                                  SIGNATURES
 
  Pursuant to the requirements of the Securities Act, the registrant has duly
caused this registration statement to be signed on its behalf by the
undersigned, thereunto duly authorized, in the City of Houston, State of
Texas, on December 20, 1996.
 
                                                   KELLEY OIL & GAS CORPORATION
 
                                                        John F. Bookout
                                                 By:__________________________
                                                        John F. Bookout
                                                      President and Chief
                                                       Executive Officer
 
                              POWERS OF ATTORNEY
 
  KNOW ALL MEN BY THESE PRESENTS, that each of the undersigned constitutes and
appoints John F. Bookout and Thomas E. Baker, and each of them, either one of
whom may act without joinder of the other, his true and lawful attorneys-in-
fact and agents, with full power of substitution and resubstitution, for him
and in his name, place and stead, in any and all capacities, to sign any or
all pre- and post-effective amendments to this Registration Statement, and to
file the same, with all exhibits thereto and other documents in connection
therewith, with the Securities and Exchange Commission, granting unto said
attorneys-in-fact and agents, and each of them, full power and authority to do
and perform each and every act and thing requisite and necessary to be done in
and about the premises, as fully to all intents and purposes as he might or
could do in person, hereby ratifying and confirming all that said attorneys-
in-fact and agents, and each of them, or the substitute or substitutes of any
or all of them, may lawfully do or cause to be done by virtue hereof.
 
  Pursuant to the requirements of the Securities Act of 1933, this
Registration Statement has been signed as of the 21st day of November, 1996 by
the following persons in the capacities indicated.
 
       John F. Bookout                                 William C. Rankin
-----------------------------                    -----------------------------
       John F. Bookout                             William C. Rankin Senior
 President, Chief Executive                        Vice President and Chief
    Officer and Director                         Financial Officer (Principal
    (Principal Executive                              Financial Officer)
          Officer)
 
 
                                                     John J. Conklin, Jr.
     Lawrence G. Marble                          -----------------------------
-----------------------------                        John J. Conklin, Jr.
     Lawrence G. Marble                                    Director
         Controller
    (Principal Accounting
          Officer)
 
 
                                                       William J. Murray
      Ralph P. Davidson                          -----------------------------
-----------------------------                          William J. Murray
      Ralph P. Davidson                                    Director
          Director
 
 
                                                      Michael B. Rothfeld
       Ogden M. Phipps                           -----------------------------
-----------------------------                         Michael B. Rothfeld
       Ogden M. Phipps                                     Director
          Director
 
                                Ward W. Woods
                        -----------------------------
                                Ward W. Woods
                                  Director