<PAGE>

                      SECURITIES AND EXCHANGE COMMISSION
                            WASHINGTON, D.C. 20549

                                   FORM 10-K

              /X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                      THE SECURITIES EXCHANGE ACT OF 1934
                  FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998

                                      OR

         / / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                        SECURITIES EXCHANGE ACT OF 1934
             FOR THE TRANSITION PERIOD FROM            TO
                                            ----------    ----------

                      COMMISSION FILE NUMBER: 333-52263*

                        MICHAEL PETROLEUM CORPORATION
            (Exact name of registrant as specified in its charter)

                                     TEXAS
        (State or Other Jurisdiction of Incorporation or Organization)

                                  76-0510239
                     (I.R.S. Employer Identification No.)

                      13101 NORTHWEST FREEWAY, SUITE 320,
                             HOUSTON, TEXAS 77040
          (Address of principal executive offices including zip code)

                               (713) 895-0909
              (Registrant's telephone number including area code)

        SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NONE

        SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE

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

     Indicate by check mark if disclosure of delinquent filers pursuant to 
Item 405 of Regulation S-K is not contained herein, and will not be 
contained, to the best of registrant's knowledge, in definitive proxy or 
information statements incorporated by reference in Part III of this Form 
10-K or any amendment to this Form 10-K:  X
                                         ---
     As of March 29, 1999, there were 10,000 shares of Michael Petroleum 
Corporation Common Stock, $0.10 par value, issued and outstanding.
                                       
                       DOCUMENTS INCORPORATED BY REFERENCE

                                     None

         * The Commission File Number refers to a Form S-4 Registration 
Statement filed by the Registrant under the Securities Act of 1933 which was 
declared effective on July 22, 1998.
<PAGE>

TABLE OF CONTENTS

<TABLE>
<CAPTION>
                                                                            PAGE
                                                                            ----
<S>      <C>                                                                <C>
Item 1.  Business
           The Company......................................................  3
           Developments in 1998.............................................  3
           Market Factors...................................................  6
           Competition......................................................  6
           Governmental Regulation..........................................  7
           Abandonment Costs................................................ 10
           Operating Hazards and Insurance.................................. 10
           Employees........................................................ 10
Item 2.  Properties......................................................... 10
           Oil and Natural Gas Reserves..................................... 10
Item 3.  Legal Proceedings.................................................. 15
Item 4.  Submission of Matters to a Vote of Security Holders................ 15
Item 5.  Market for Registrant's Common Equity and Related 
           Stockholder Matters.............................................. 15
Item 6.  Selected Consolidated Financial Data............................... 15
Item 7.  Management's Discussion and Analysis of Results of Operations
           and Financial Condition.......................................... 16
             General........................................................ 16
             Results of Operations.......................................... 16
             Liquidity and Capital Resources................................ 18
Item 7A  Quantitative and Qualitative Disclosures About Market Risk......... 29
Item 8.  Financial Statements............................................... 30
Item 9.  Changes in and Disagreements with Accountants on Accounting
             and Financial Disclosure....................................... 50
Item 10. Directors and Executive Officers of the Registrant................. 50
Item 11. Executive Compensation............................................. 51
Item 12. Security Ownership of Certain Beneficial Owners and Management..... 53
Item 13. Certain Relationships and Related Transactions..................... 53
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.... 54
</TABLE>

PRELIMINARY NOTE:  The statements regarding future financial performance and 
results and oil and natural gas prices and the other statements which are not 
historical facts contained in this report are forward-looking statements. The 
words "expect," "project," "estimate," "believe," "anticipate," "intend," 
"budget," "predict" and similar expressions are also intended to identify 
forward-looking statements. Such statements involve risks and uncertainties, 
including, but not limited to, market factors, market prices of natural gas 
and oil, results for future drilling and marketing activity, the need for and 
availability of capital, future production and costs and other factors 
detailed herein and in the Company's other Securities and Exchange Commission 
filings. Should one or more of these risks or uncertainties materialize, or 
should underlying assumptions prove incorrect, actual outcomes may vary 
materially from those indicated. See Item 7. "Management's Discussion and 
Analysis of Results of Operations--Cautionary Statements Regarding 
Forward-Looking Information."

<PAGE>

                                     PART I

ITEM 1.  BUSINESS

THE COMPANY

         Michael Petroleum Corporation (the "Company" or "Michael") is 
engaged in the acquisition, exploitation and development of oil and natural 
gas properties, principally in the Lobo Trend of South Texas (the "Lobo 
Trend"). The Company has significantly expanded its production and reserve 
base in recent years through development drilling and exploitation activities 
and by acquiring producing and undeveloped properties. On March 31, 1998 and 
April 2, 1998, the Company closed separate acquisitions of Lobo Trend 
properties with Enron Oil and Gas Company ("Enron") (the "Enron Acquisition") 
and Conoco Inc. ("Conoco") (the "Conoco Acquisition") (collectively, the 
"Transactions"), pursuant to which the Company acquired interests in 170 
gross (98 net) wells covering approximately 46,900 gross acres. In April 
1998, the Company acquired leasehold interests in undeveloped acreage (the 
"Lobo Lease") from Mobil Producing Texas and New Mexico Inc. ("Mobil"), 
covering approximately 39,636 gross acres in the Lobo Trend. The interests in 
properties acquired included acreage that was geographically close and 
geologically similar to the Company's other properties. The Company applied 
approximately $78.3 million in net proceeds from the sale of its 11 1/2% 
Senior Notes due 2005, Series A in connection with the closing of the 
Transactions and the Lobo Lease. See "--Developments in 1998" below and Item 
7. "Management's Discussion and Analysis of Results of Operations and 
Financial Condition".

         The Lobo Trend, which is located in Webb and Zapata counties in 
South Texas, covers in excess of one million gross acres and contains 
multi-pay reservoirs of oil and natural gas. Since 1991, Webb and Zapata 
counties collectively have constituted one of the largest onshore natural gas 
producing regions in the United States. Although over 3,500 wells have been 
drilled and cumulative production from the Lobo Trend since its discovery in 
1973 exceeds 6.3 trillion cubic feet of natural gas equivalents, the Lobo 
Trend is believed to be only partially exploited, with existing wells 
producing from only approximately 125,000 acres. The primary geologic target 
in the Lobo Trend is the Lobo sand series of the lower Wilcox formation, 
which contains three primary objectives. Two secondary objectives also exist, 
one above the three Lobo sands and one below. The Company believes that the 
existence of these multi-pay reservoirs reduces drilling risk and enhances 
the profitability of invested capital.

         The Company began its operations in 1983 and focused on developing 
prospects in South Texas. Since the early 1990s, the Company has become an 
increasingly active participant in development drilling in the Lobo Trend. In 
1996, the Company acquired interests in approximately 21,000 developed and 
undeveloped gross acres in the Lobo Trend (the "1996 Acquisition"). The 
Company uses 3-D seismic imaging and other advanced technologies in the 
development and exploitation of its properties. As of December 31, 1998, 3-D 
seismic data had been obtained over approximately 90% of the Company's 
properties. See generally, Item 2. "Properties--Glossary of Certain Industry 
Terms."

DEVELOPMENTS IN 1998

SALE AND EXCHANGE OF SENIOR NOTES

         On April 2, 1998, the Company completed a debt offering in a private 
placement exempt from registration under the Securities Act of 1933, of $135 
million of 11 1/2% Senior Notes, due 2005, Series A  (the "Series A Notes"). 
A portion of the net proceeds from the sale were used to repay outstanding 
borrowings under a previous credit agreement (the "T.E.P. Financing") of 
approximately $28 million. Under the T.E.P. Financing, a 30% net profits 
interest in all of the Company's oil and natural gas properties had been 
granted to the lender, along with a warrant to purchase up to 5% of the 
Company's common stock. On April 2, 1998, the T.E.P. Financing Agreement was 
terminated, and the unamortized balance of the notes payable discount, the 
deferred debt issuance costs and certain fees incurred at closing were 
written off and reflected in the income statement as an extraordinary loss, 
net of taxes.

         On July 22, 1998, the Securities and Exchange Commission ("SEC") 
declared the Company's Registration Statement on Form S-4 effective pursuant 
to Section 8(a) of the Securities Act. The Registration Statement had been 
filed to cover offers of exchange of the Company's 11 1/2% Senior Notes Due 
2005, Series B (the "Series B Notes") for the Series A Notes.

<PAGE>

As of September 4, 1998, all of the $135 million original principal amount of 
the Series A Notes had been exchanged for Series B Notes, the terms of which 
are substantially identical to the terms of the Series A Notes. The effective 
interest rate under the Series B Notes for the year ended December 31, 1998 
was 12.04%.

CREDIT FACILITY

         In May 1998, the Company entered into a four-year credit facility 
(the "Credit Facility") with Christiania Bank og KreditKasse ("Christiania") 
which provides maximum loan amounts totaling $50.0 million, subject to 
borrowing base limitations. The borrowing base will be redetermined 
semiannually by Christiania based on the Company's proved oil and natural gas 
reserves beginning at March 31, 1999. Although the initial borrowing base was 
$30 million, and effective November 9, 1998, the borrowing base was increased 
by $5 million, the new borrowing base, effective April 1, 1999, was reduced 
to $23 million. The maturity date of all indebtedness under the Credit 
Facility is May 28, 2002. The effective interest rate under the Credit 
Facility for the year ended December 31, 1998 was 6.8%. At December 31, 1998, 
the Company was in default of certain financial covenants under the Credit 
Facility but has obtained waivers of such defaults from Christiania and 
amended the Credit Facility. See Item 7. "Management's Discussion and 
Analysis of Results of Operation and Financial Condition--Financing 
Arrangements" and "--Cautionary Statements Regarding Forward-Looking 
Information-Future Need For and Availability of Capital," "--Restrictions 
Imposed by Lenders" and "--Incurrence of Substantial Indebtedness."

ENRON ACQUISITION

         The Enron Acquisition was consummated on March 31, 1998. Pursuant to 
a Purchase and Sale Agreement, Enron conveyed to the Company (i) interests 
in certain oil and natural gas leases covering approximately 7,500 gross 
acres in Hidalgo County and Zapata County, Texas, (ii) certain interests in 
leases covering approximately 37,500 gross acres located in Webb County, 
Texas (the "Ranch Lands") covering the interval between the surface and 100 
feet below the stratigraphic equivalent of the base of the Lobo 6 Sand, (iii)
all of Enron's interests in and to a 2.67% non-participating term royalty 
interest in and to the Ranch Lands limited in depth to the interval covered 
by the lease granted on the Ranch Lands and terminating simultaneously 
therewith and (iv) all seismic data owned by Enron covering these properties 
described in (i) and (ii) above.

         The purchase price for the Enron Acquisition was $45.8 million, net 
of closing and post-closing adjustments, and the conveyance by the Company to 
Enron of certain oil and natural gas properties in Webb County, Texas. The 
dollar portion of the purchase price was paid in the form of a promissory 
note issued by the Company in the original principal amount of $45.8 million 
which was repaid on April 2, 1998, the closing date of the sale of the Series 
A Notes and the Conoco Acquisition. In addition, the Company granted to Enron 
a non-exclusive license to use the seismic data it conveyed to the Company.

         Under the Enron Purchase and Sale Agreement, the Company acquired 
the properties on an "as is" basis. The Purchase and Sale Agreement also 
provided for limited environmental indemnities. The Company must indemnify 
Enron for certain environmental liabilities incurred by Enron, including 
claims arising in whole or in part from the sole or concurrent negligence or 
gross negligence of Enron.

                                       4
<PAGE>

CONOCO ACQUISITION

         The Conoco Acquisition was consummated on April 2, 1998, with Conoco 
conveying to the Company a leasehold interest in all of Conoco's interests in 
approximately 39,000 gross acres located in Webb County, Texas, covering the 
same interval covered by the Enron leases. The Company paid $22.5 million, 
which reflected certain closing adjustments. The Company used a portion of 
the net proceeds from the sale of the Series A Notes to pay the purchase 
price of the Conoco Acquisition.

         Under the Conoco Purchase and Sale Agreement, the Company acquired 
the properties on an "as is" basis. The Purchase and Sale Agreement also 
provided for limited environmental indemnities. The Company must indemnify 
Conoco for certain environmental liabilities incurred by Conoco, including 
claims arising in whole or in part from the sole or concurrent negligence, 
gross negligence or strict liability of Conoco.

LOBO LEASE TRANSACTION

         By agreement dated April 20, 1998, the Company acquired from Mobil 
certain leasehold interests in undeveloped acreage in the Lobo Trend in Webb 
County, Texas. Under this agreement, Mobil assigned to the Company its 
interests in two existing leases and granted by lease interests in additional 
undeveloped acreage under an oil and gas lease having a primary term of seven 
years. The lease, which has an effective date of January 1, 1998, covers 
39,636 gross acres and covers the same interval covered by the Enron and 
Conoco leases. Excluded from the lease grant were existing productive wells 
and certain drilling units on the subject properties. The lease contains 
provisions obligating the Company to indemnify Mobil for certain liabilities 
incurred by Mobil as a result of the Company's operations on the Lobo Lease 
properties, including liabilities for violations of environmental laws. The 
Company and Mobil also agreed that effective May 1, 1998, Michael would be 
appointed operator with respect to the properties covered by the Lobo Lease 
pursuant to a joint operating agreement between them. 

         As part of the consideration for the Lobo Lease and related matters, 
the Company agreed to make future deliveries to Mobil of 4.0 Bcf of natural 
gas. On April 23, 1998, the Company entered into a contract to secure 
delivery of this volume of natural gas from a third party for $9.98 million.

OTHER ACQUISITIONS

         On July 31, 1998, the Company acquired all of the common stock of 
two companies owning non-operating working interests in 132 wells 
on approximately 17,000 gross (500 net) acres, primarily in the Lobo Trend 
located in Webb and Zapata Counties in Texas for $2.6 million. The working 
interest percentages range from 0.5% to 15%, with an average working interest 
of approximately 2.5% and an average net revenue interest of approximately 
2.0%.

         In December 1998, the Company loaned $1.5 million to a joint venture 
between a Mexican construction company and a Texas limited liability company 
to participate in the drilling of 38 natural gas wells for Petroleos 
Mexicanos ("Pemex") in the Burgos Basin of Northern Mexico. The Mexican 
construction company has a 51% ownership interest in the joint venture and 
the Texas limited liability company has a 49% ownership interest. The note is 
due December 1999 and bears interest at 12% per annum. The Company has an 
option to convert the note receivable to a 50% equity interest in the Texas 
limited liability company holding the 49% interest in the venture.

                                       5
<PAGE>

MARKET FACTORS

         The revenues generated by the Company's operations are highly 
dependent upon the prices of and demand for oil and natural gas. The price 
received by the Company for its oil and natural gas production depends on 
numerous factors beyond the Company's control. Historically, the markets for 
oil and natural gas have been volatile and are likely to continue to be 
volatile in the future. Prices for oil and natural gas are subject to wide 
fluctuation in response to relatively minor changes in the supply and demand 
for oil and natural gas, market uncertainty and a variety of additional 
factors. These factors include the level of consumer product demand, weather 
conditions, domestic and foreign governmental regulations, the price and 
availability of alternative fuels, political conditions in the Middle East, 
the actions of the Organization of Petroleum Exporting Countries, the foreign 
supply of oil and natural gas and overall economic conditions. It is 
impossible to predict future oil and natural gas price movements with any 
certainty. Declines in oil and natural gas prices may adversely affect the 
Company's financial condition, liquidity and results of operations. Crude oil 
prices are generally determined by global supply and demand. After sinking to 
a five-year low at the end of 1993, oil prices reached their highest levels 
since the 1990 Persian Gulf War during fourth quarter 1996 and January 1997. 
Posted crude oil prices ranged from $17 to $20 during most of 1997, then 
declined to a $16 average in December 1997. Crude oil prices continued to 
decline throughout 1998, dropping to a West Texas Intermediate price of $8.00 
per barrel in December 1998, the lowest level since 1978. This decline has 
been caused by low demand, as well as the failure of OPEC, at its November 
1998 meeting, to further reduce production quotas. Low demand has been caused 
by warmer than normal winter temperatures and a slow recovery in Asian 
economies.

         Natural gas prices are influenced by national and regional supply 
and demand, which is often dependent upon weather conditions. Natural gas 
competes with alternative energy sources as a fuel for heating and the 
generation of electricity. Generally because of colder weather, storage 
concerns and U.S. economic growth, prices remained relatively high during 
most of 1996 and 1997. Gas prices declined, however, in December 1997 and 
have remained lower throughout 1998, primarily because the winters of 
1997-1998 and 1998-1999 were abnormally mild in the central and eastern U.S. 
See Item 7. "Management's Discussion and Analysis of Financial Condition and 
Results of Operations."

         The Company currently markets all of its natural gas through 
Upstream Energy Services, L.L.C. ("Upstream") pursuant to the terms of an 
agreement dated effective as of November 1, 1998 (the "Sales Agreement"). The 
Company and the predecessor to Upstream had similar marketing arrangements in 
effect from 1991 to October 1998. Under the Sales Agreement, the Company has 
agreed to sell, and Upstream has agreed to market all of the natural gas 
produced from properties owned or operated by the Company at the price 
realized by Upstream from the sale of such natural gas production less (i) 
the costs incurred by Upstream in the transportation, treating and handling 
of the gas prior to resale and (ii) marketing compensation ranging from $0.03 
to $0.01 per Mmbtu sold, as measured at the point of delivery. The marketing 
compensation is calculated as follows:
<TABLE>
<CAPTION>
              VOLUMETRIC TIER (MMBTU/DAY)   MARKETING FEE
              ---------------------------   -------------
              <S>                           <C>
              First 20,000                  $0.03/MMbtu

              20,001 to 40,000              $0.02/MMbtu

              All volumes over 40,000       $0.01/MMbtu
</TABLE>
         The Sales Agreement is effective for a one-year period and is 
renewable quarterly thereafter, subject to either party giving 60 days 
written notice of termination. Until August 1997, the Company's Chief 
Executive Officer owned an aggregate of approximately 20% of the capital 
stock of Upstream. See Item 13. "Certain Relationships and Related 
Transactions."

         In conjunction with the 1996 Acquisition, Conoco (as the successor 
in interest to the seller) and the Company entered into a Gas Exchange 
Agreement whereby such parties agreed that the Company would deliver to 
Conoco all of the natural gas produced from the leases acquired in the 1996 
Acquisition at the point(s) at which such gas enters the transmission 
pipelines owned by Lobo Pipeline Company ("Lobo Pipeline") (the "delivery 
point") in exchange for natural gas in the same quantity and quality 
delivered by Conoco at the Agua Dulce hub near Corpus Christi, Texas. The 
parties' obligations under the Gas Exchange Agreement are subject to the 
natural gas delivered and the pipeline meeting certain specifications. The 
title to the Company's gas vests in Conoco at the delivery point, except to 
the extent such amount exceeds the amount of redelivered gas at the 
redelivery point, in which case the Company retains title and ownership of 
such excess, which is then transported by Lobo Pipeline pursuant to an 
Interruptible Gas Transportation Agreement. The consideration received by 
Lobo Pipeline is $0.17 per Mcf for compression, transportation and 
dehydration.

COMPETITION

         The oil and natural gas industry is highly competitive, and the 
Company encounters competition from other oil and natural gas companies in 
all areas of its operations, including the acquisition of seismic, lease 
options, exploratory prospects and proven properties. The Company's 
competitors in the Lobo Trend area include major integrated oil and natural 
gas companies, including Chevron Corporation, Conoco, Enron Corp. and Sonat 
Exploration Company, and numerous independent oil and natural gas companies, 
individuals and drilling and income programs. Many of the Company's 
competitors, including those with whom it competes in the Lobo Trend, are 
large, well-established companies with substantially larger operating staffs 
and significantly greater capital resources than those of the Company and 
which, in many instances, have been engaged in the oil and natural gas 
business for a much longer time than the Company. Such companies may be able 
to pay more for exploratory 

                                       6
<PAGE>

prospects and productive oil and natural gas properties and may be able to 
define, evaluate, bid for and purchase a greater number of properties and 
prospects than could the Company, given its limited financial and human 
resources. In addition, such companies may be able to expend greater 
resources on the existing and changing technologies that the Company believes 
are and will be increasingly important to the current and future success of 
oil and natural gas companies.

         The Company's ability to acquire additional properties in the future 
will be dependent upon its ability to evaluate and select suitable properties 
and to consummate transactions in this highly competitive market. The Company 
believes that the technological expertise and experience of its management in 
exploiting the Lobo Trend, as well as the Company's relationships with 
landowners in the area, generally enable it to compete effectively in the 
Lobo Trend. However, the business of developing or acquiring reserves is 
capital intensive, especially in the Lobo Trend area where the land blocks 
typically range between 5,000 and 50,000 acres. The Company will require 
additional financing or participation of industry partners to effect future 
acquisitions in this area. Such additional financing may take the form of 
equity securities, debt securities or some combination thereof, and there can 
be no assurance that such financing will be available on terms that are 
acceptable to the Company, if at all. Failure to secure such financing or to 
locate industry partners would adversely affect the Company's ability to 
compete with these other companies for lease acreage as it may become 
available. See Item 7. "Management's Discussion and Analysis of Results of 
Operations and Financial Condition." In addition, to the extent that the 
Company engages in oil and natural gas exploration and production activities 
on properties in geographic areas other than the Lobo Trend area, the Company 
may be subject to additional competitive disadvantages due to its lack of 
experience in and familiarity with prospect characteristics of those areas.

GOVERNMENTAL REGULATION

         Various aspects of the Company's oil and natural gas operations are 
subject to extensive and continually changing regulation, as legislation 
affecting the oil and natural gas industry is under constant review for 
amendment or expansion. Numerous departments and agencies, both federal and 
state, are authorized by statute to issue, and have issued, rules and 
regulations binding upon the oil and natural gas industry and its individual 
members. The Federal Energy Regulatory Commission (the "FERC") regulates the 
transportation and sale for resale of natural gas in interstate commerce 
pursuant to the Natural Gas Act of 1938 (the "NGA") and the Natural Gas 
Policy Act of 1978 (the "NGPA"). In the past, the federal government has 
regulated the prices at which oil and natural gas could be sold. While sales 
by producers of natural gas and all sales of crude oil, condensate and 
natural gas liquids can currently be made at uncontrolled market prices, 
Congress could reenact price controls in the future. Deregulation of wellhead 
sales in the natural gas industry began with the enactment of the NGPA in 
1978. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act (the 
"Decontrol Act"). The Decontrol Act removed all remaining NGA and NGPA price 
and nonprice controls affecting wellhead sales of natural gas effective 
January 1, 1993.

         The Company's operations currently are located primarily in Texas. 
Thus, the Company's business is subject to environmental regulation on the 
state level primarily by the Railroad Commission of Texas and the Texas 
Natural Resource Conservation Commission. The Railroad Commission of Texas 
regulations may require the Company to obtain permits and drilling bonds for 
the drilling of wells. Additionally, the Railroad Commission of Texas 
regulates the spacing of wells, plugging and abandonment of such wells and 
the remediation of contamination caused by most types of exploration and 
production wastes. The Railroad Commission requirements for remediation of 
contamination are, for the most part, administered on a case-by-case basis. 
The Company expects that such regulations will be formalized in the future 
and will in all likelihood become more stringent.

REGULATION OF SALES AND TRANSPORTATION OF NATURAL GAS

         The Company's sales of natural gas are affected by the availability, 
terms and cost of transportation. The price and terms for access to pipeline 
transportation are subject to extensive regulation. In recent years, the FERC 
has undertaken various initiatives to increase competition within the natural 
gas industry. As a result of initiatives like FERC Order No. 636, issued in 
April 1992, the interstate natural gas transportation and marketing system 
has been substantially restructured to remove various barriers and practices 
that historically limited nonpipeline natural gas sellers, including 
producers, from effectively competing with interstate pipelines for sales to 
local distribution companies and large industrial and commercial customers. 
The most significant provisions of Order No. 636 require that interstate 
pipelines provide firm and interruptible transportation service on an open 
access basis that is equal for all natural gas suppliers. In many instances, 
the results of Order No. 636 and related initiatives have been to 
substantially reduce or eliminate the interstate pipelines' traditional role 
as wholesalers of natural gas in favor of providing only storage and 
transportation services. While the United States Court of Appeals upheld most 
of Order 

                                       7
<PAGE>

No. 636 in 1997, certain related FERC orders, including the individual pipeline
restructuring proceedings, are still subject to judicial review and may be 
reversed or remanded in whole or in part. While the outcome of these 
proceedings cannot be predicted with certainty, the Company does not believe 
that it will be affected materially differently than its competitors.

         The FERC has also announced several important transportation-related 
policy statements and proposed rule changes, including a statement of policy 
and a request for comments concerning alternatives to its traditional 
cost-of-service ratemaking methodology to establish the rates interstate 
pipelines may charge for their services. A number of pipelines have obtained 
FERC authorization to charge negotiated rates as one such alternative. Both 
the policy statement and individual pipeline negotiated rate authorizations 
are currently subject to appeal before the U.S. Court of Appeals for the D.C. 
Circuit. In February 1997, the FERC announced a broad inquiry into issues 
facing the natural gas industry to assist the FERC in establishing regulatory 
goals and priorities in the post-Order No. 636 environment. In October 1997, 
the United States Court of Appeals for the Fifth Circuit vacated a FERC 
decision and remanded it to the agency with directions to reconsider the 
criteria FERC used to distinguish nonjurisdictional gathering from 
jurisdictional transportation on offshore pipeline systems. The final outcome 
of these and other issues being considered by the FERC, and their effect on 
the Company and its competitors cannot be predicted with certainty.

         Additional proposals and proceedings that might affect the natural 
gas industry are pending before Congress, the FERC, state commissions and the 
courts. The natural gas industry historically has been very heavily 
regulated; therefore, there is no assurance that the less stringent 
regulatory approach recently pursued by the FERC and Congress will continue.

OIL PRICE CONTROLS AND TRANSPORTATION RATES

         Sales of crude oil, condensate and natural gas liquids by the 
Company are not currently regulated and are made at market prices. The price 
the Company receives from the sale of these products may be affected by the 
cost of transporting the products to market.

ENVIRONMENTAL

         Extensive federal, state and local laws regulating the discharge of 
materials into the environment or otherwise relating to the protection of the 
environment affect the Company's oil and natural gas operations. Numerous 
governmental departments issue rules and regulations to implement and enforce 
such laws, which are often difficult and costly to comply with and which 
carry substantial civil and even criminal penalties for failure to comply. 
Some laws, rules and regulations relating to protection of the environment 
may, in certain circumstances, impose strict liability for environmental 
contamination, rendering a person or entity liable for environmental damages 
and cleanup costs without regard to negligence or fault on the part of such 
person or entity. Other laws, rules and regulations may restrict the rate of 
oil and natural gas production below the rate that would otherwise exist or 
even prohibit exploration and production activities in sensitive areas. In 
addition, state laws often require various forms of remedial action to 
prevent pollution, such as closure of inactive pits and plugging of abandoned 
wells. The regulatory burden on the oil and gas industry increases the 
Company's cost of doing business and consequently affects the Company's 
profitability. The Company believes that it is in substantial compliance with 
current applicable environmental laws and regulations and that continued 
compliance with existing requirements will not have a material adverse impact 
on the Company's operations. However, environmental laws and regulations have 
been subject to frequent changes over the years, and the imposition of more 
stringent requirements could have a material adverse effect upon the capital 
expenditures or competitive position of the Company.

         The Comprehensive Environmental Response, Compensation and Liability 
Act ("CERCLA") imposes liability, without regard to fault or the legality of 
the original act, on certain classes of persons that are considered to be 
responsible for the release of a "hazardous substance" into the environment. 
These persons include the current or former owner or operator of the disposal 
site or sites where the release occurred and companies that disposed or 
arranged for the disposal of hazardous substances at the disposal site. Under 
CERCLA such persons may be subject to joint and several liability for the 
costs of investigating and cleaning up hazardous substances that have been 
released into the environment, for damages to natural resources and for the 
costs of certain health studies. Comparable state statutes also impose 
liability on the owner or operator of a property for remediation of 
environmental contamination existing on such property. In addition, companies 
that incur liability frequently confront third party claims because it is not 
uncommon for neighboring landowners and other third parties to file claims 
for personal injury and property damage allegedly caused by hazardous 
substances or other pollutants released into the environment from a polluted 
site.

                                       8
<PAGE>

         The Company currently owns or leases, and has in the past owned or 
leased, numerous properties that have been used for the exploration and 
production of oil and natural gas and for other uses associated with the oil 
and gas industry. Although the Company has followed operating and disposal 
practices that it considered appropriate under applicable laws and 
regulations, hydrocarbons or other wastes may have been disposed of or 
released on or under the properties owned or leased by the Company or on or 
under other locations where such wastes were taken for disposal. In addition, 
the Company owns or leases properties that have been operated by third 
parties in the past. The Company could incur liability under CERCLA or 
comparable state statutes for contamination caused by wastes it generated or 
for contamination existing on properties it owns or leases, even if the 
contamination was caused by the waste disposal practices of the prior owners 
or operators of the properties.

         The Federal Solid Waste Disposal Act, as amended by the Resource 
Conservation and Recovery Act of 1976 ("RCRA"), regulates the generation, 
transportation, storage, treatment and disposal of hazardous wastes and can 
require cleanup of hazardous waste disposal sites. RCRA currently excludes 
drilling fluids, produced waters and other wastes associated with the 
exploration, development or production of oil and natural gas from regulation 
as "hazardous waste." A similar exemption is contained in many of the state 
counterparts to RCRA. Disposal of such nonhazardous oil and natural gas 
exploration, development and production wastes usually is regulated by state 
law. Other wastes handled at exploration and production sites or used in the 
course of providing well services may not fall within this exclusion. 
Moreover, stricter standards for waste handling and disposal may be imposed 
on the oil and gas industry in the future. From time to time legislation has 
been proposed in Congress that would revoke or alter the current exclusion of 
exploration, development and production wastes from the RCRA definition of 
"hazardous wastes" thereby potentially subjecting such wastes to more 
stringent handling and disposal requirements. If such legislation were 
enacted, or if changes to applicable state regulations required the wastes to 
be managed as hazardous wastes, it could have a significant impact on the 
operating costs of the Company, as well as the oil and gas industry in 
general.

         The Company's operations are also subject to the Clean Air Act (the 
"CAA") and comparable state and local requirements. Amendments to the CAA 
were adopted in 1990 and contain provisions that may result in the gradual 
imposition of certain pollution control requirements with respect to air 
emissions from operations of the Company. The Company may be required to 
incur certain capital expenditures in the next several years for air 
pollution control equipment in connection with obtaining and maintaining 
operating permits and approvals for air emissions. However, the Company 
believes its operations will not be materially adversely affected by any such 
requirements, and the requirements are not expected to be any more burdensome 
to the Company than to other similarly situated companies involved in oil and 
natural gas exploration and production activities.

         The Federal Water Pollution Control Act of 1972 (the "FWPCA") 
imposes restrictions and strict controls regarding the discharge of wastes, 
including produced waters and other oil and natural 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 unauthorized discharges of oil and other hazardous substances 
and imposes substantial potential liability for the costs of removal or 
remediation. State laws governing discharges to water 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 has promulgated regulations that require many oil and natural gas 
production sites, as well as other facilities, to obtain permits to discharge 
storm water runoff. The Company believes that compliance with existing 
requirements under the FWPCA and comparable state statutes will not have a 
material adverse effect on the Company's financial condition, results of 
operations or cash flows of the Company.

         The Company maintains insurance against "sudden and accidental" 
occurrences which may cover some, but not all, of the environmental risks 
described above. Most significantly, the insurance maintained by the Company 
may not cover the risks described above that are not attributable to a 
single, abrupt event. Further, there can be no assurance that such insurance 
will continue to be available to cover all such costs or that such insurance 
will be available at premium levels that justify its purchase. The occurrence 
of a significant event not fully insured or indemnified against could have a 
material adverse effect on the Company's financial condition, results of 
operations or cash flows.

REGULATION OF OIL AND NATURAL GAS EXPLORATION AND PRODUCTION

                                       9
<PAGE>

         Exploration and production operations of the Company are subject to 
various types of regulation at the federal, state and local levels. Such 
regulations include requiring permits and drilling bonds for the drilling of 
wells, regulating the location of wells, the method of drilling and casing 
wells, and the surface use and restoration of properties upon which wells are 
drilled. Many states also have statutes or regulations addressing 
conservation matters, including provisions for the unitization or pooling of 
oil and gas properties, the establishment of maximum rates of production from 
oil and gas wells and the regulation of spacing, plugging and abandonment of 
such wells. Some state statutes limit the rate at which oil and gas can be 
produced from the Company's properties. See "Item 7. Management's Discussion 
and Analysis of Financial Condition and Results of Operations."

ABANDONMENT COSTS

         The Company is responsible for payment of plugging and abandonment 
costs on oil and natural gas properties pro rata to its working interest. 
Historically, the ultimate aggregate salvage value of lease and well 
equipment located on the Company's properties has not exceeded the costs of 
abandoning such properties. There can be no assurance, however, that this 
historical trend will continue or that the Company will be successful in 
avoiding additional expenses in connection with the abandonment of any of its 
properties. In addition, abandonment costs and their timing may vary due to 
many factors including actual production results, inflation rates and changes 
in environmental laws and regulations.

OPERATING HAZARDS AND INSURANCE

         The oil and natural gas business involves a variety of operating 
risks, including the risk of fire, explosion, blowout, pipe failure, casing 
collapse, unusual or unexpected formation pressures and environmental hazards 
such as oil spills, gas leaks, ruptures and discharges of toxic gases, the 
occurrence of any of which could result in substantial losses to the Company 
due to injury or loss of life, severe damage to or destruction of property, 
natural resources and equipment, pollution or other environmental damage, 
cleanup responsibilities, regulatory investigation and penalties and 
suspension of operations.

         In accordance with customary industry practice, the Company 
maintains insurance against some, but not all, of the operating risks 
described above. The Company's insurance does not cover business interruption 
or protect against loss of revenues. There can be no assurance that any 
insurance obtained by the Company will be adequate to cover any losses or 
liabilities. The Company cannot predict the continued availability of 
insurance or the availability of insurance at economic rates. The occurrence 
of a significant event against which it is not fully insured or indemnified 
could have a material adverse effect on the Company's financial condition, 
results of operations or cash flows.

EMPLOYEES

         At December 31, 1998, the Company employed 27 full-time employees, 
and numerous independent contractors. The Company believes that its 
relationships with its employees are satisfactory. None of the Company's 
employees are covered by a collective bargaining agreement. From time to 
time, the Company utilizes the services of independent consultants and 
contractors to perform various professional services, particularly in the 
areas of construction, design, well site surveillance, permitting and 
environmental assessment.

ITEM 2.  PROPERTIES

LOBO TREND

         The Company owns interests in developed and undeveloped properties 
in South Texas, primarily in the Lobo Trend and undeveloped acreage in South 
Texas. The Company's Lobo Trend properties represented substantially all of 
its reserves and PV-10 Value, as of December 31, 1998. The Company is the 
operator of over 65% of the wells in which it has an interest.

         The Lobo Trend in Webb and Zapata Counties in South Texas is one of 
the largest onshore natural gas producing regions in the United States. The 
primary geologic target in the Lobo Trend is the Lobo sand series of the 
Lower Wilcox formation, which contains multiple pay sands. The primary 
objectives in the Lobo Trend are the Lobo 1 and Lobo 6 sands. Other pay sands 
exist at shallower and deeper horizons in certain areas of the trend. 
Extensive faulting has trapped hydrocarbons in the Lobo Trend producing 
horizons and has created a complex geological environment. Until recently, 
2-D seismic and subsurface well control were the primary means for developing 
the field. The introduction of 3-D seismic to the area in the early 1990s has 
improved drilling success rates, and the Company has similarly experienced an 
overall increase in its drilling success rates in the Lobo Trend as 
technology has evolved.

         The Company's Lobo Trend production is from reservoirs at depths 
between 6,000 to 14,000 feet. Most of the production horizons are of low 
permeability and must be fracture stimulated to improve rates of production. 
As a result, a typical well has a high initial production rate which declines 
rapidly and is followed by a long period of production at a lower rate with a 
gradual decline.

OIL AND NATURAL GAS RESERVES

         The following table sets forth estimated net proved natural gas and 
oil and condensate reserves of the Company and the present value of estimated 
future net cash flows related to such reserves as of December 31, 1996, 1997 
and 1998. The reserve data and present values presented have been estimated 
by Huddleston & Co., Inc. For further information concerning the present 
value of future net revenue from these proved reserves, see Note 11 of Notes 
to Consolidated Financial Statements of the Company. See also "Item 7. 
Management's Discussion and Analysis of Results of Operations and Financial 
Condition".
<TABLE>
<CAPTION>
                                                                                 AS OF DECEMBER 31,
                                                                    -------------------------------------------
                                                                      1996             1997               1998
                                                                      ----             ----               ----
<S>                                                                 <C>              <C>               <C>
Estimated proved reserves: 
  Oil and condensate (MBbls)                                            239              265              4,923
  Natural gas (Mmcf)                                                 49,246           51,165            189,753

                                       10
<PAGE>

  Natural gas equivalents (Mmcfe)                                    50,678           52,754            219,291
Proved developed reserves as a percentage of proved reserves             34%              45%              27.2%
PV-10 Value (dollars in thousands)(1)                               $60,727          $51,487           $132,638
</TABLE>

(1)  PV-10 Value represents the present value of estimated future net 
     revenues before income tax discounted at 10% using prices in effect at 
     the end of the respective periods presented and including the effects of 
     hedging activities. In accordance with applicable requirements of the SEC,
     estimates of the Company's proved reserves and future net revenues are 
     made using oil and natural gas sales prices estimated to be in effect as 
     of the date of such reserve estimates and are held constant throughout the
     life of the properties (except to the extent a contract specifically 
     provides for escalation). The average prices used in calculating historical
     PV-10 Value as of December 31, 1998 were $9.17 per Bbl of oil and $1.85 per
     Mcf of natural gas, compared to $15.91 per Bbl of oil and $2.42 per Mcf 
     of natural gas as of December 31, 1997, and $23.86 per Bbl of oil and 
     $2.76 per Mcf of natural gas as of December 31, 1996.

         There are numerous uncertainties inherent in estimating quantities 
of proved oil and natural gas reserves and in projecting future rates of 
production and timing of development expenditures, including many factors 
beyond the control of the producer. The reserve data set forth herein 
represents estimates only. Reserve engineering is a subjective process of 
estimating underground accumulations of oil and natural gas that cannot be 
measured in an exact manner, and the accuracy of any reserve estimate is a 
function of the quality of available data and of engineering and geological 
interpretation and judgment. As a result, estimates made by different 
engineers often vary. In addition, results of drilling, testing and 
production subsequent to the date of an estimate may justify revision of such 
estimates, and such revisions may be material. Accordingly, reserve estimates 
are generally different from the quantities of oil and natural gas that are 
ultimately recovered. Furthermore, the estimated future net revenues from 
proved reserves and the present value thereof are based upon certain 
assumptions, including future prices, production levels and costs, that may 
not prove correct.

         No estimates of proved reserves comparable to those included herein 
have been included in reports to any federal agency.

PRODUCTION, PRICES AND EXPENSES

         The following table presents certain information with respect to oil 
and natural gas production, prices and expenses attributable to oil and 
natural gas property interests owned by the Company for the years ended 
December 31, 1996, 1997, and 1998.

<TABLE>
<CAPTION>
                                                                       YEAR ENDED DECEMBER 31,
                                                              -----------------------------------------
                                                               1996             1997              1998
                                                               ----             ----              ----
<S>                                                           <C>              <C>               <C>
Production volumes:
  Oil and condensate (MBbls)                                      37               21                79
  Natural gas (Mmcf)                                           1,324            3,685            10,510
    Total (Mmcfe)                                              1,546            3,811            10,984
Average realized prices:
  Oil, condensate and natural gas liquids (per Bbl)           $20.05           $18.95            $11.19
  Natural gas (per Mcf)                                         2.15             2.33              2.07
  Natural gas equivalents (per Mcfe) (1)                        2.32             2.35              2.06
Expenses (per MCFE):
  Production costs                                              1.25             0.49              0.37
  Depreciation, depletion and amortization                      0.66             0.96              1.14
  Impairment of oil and gas properties                          0.10             0.06              0.49
  General and administrative, net                               0.27             0.26              0.16
</TABLE>

(1)  Includes effects of hedging transactions.

PRODUCTIVE WELLS

         The following table sets forth the number of productive wells in 
which the Company owned an interest as of December 31, 1997 and 1998:

<TABLE>
<CAPTION>
                             1997                  1998
                        --------------        -------------
                        GROSS      NET        GROSS     NET
<S>                     <C>        <C>        <C>       <C>
Oil                        --       --            7      --
Natural gas                78       43          438     184
                         ----     ----         ----    ----

                                       11
<PAGE>

  Total                    78       43          445     184
                         ====     ====         ====    ====
</TABLE>

         Productive wells consist of producing wells and wells capable of 
production, including natural gas wells awaiting pipeline connection. Wells 
that are completed in more than one producing horizon are counted as one well.

ACREAGE

The following table sets forth the Company's developed and undeveloped gross 
and net leasehold acreage as of December 31, 1997 and 1998.

<TABLE>
<CAPTION>
                                                 1997
                    ------------------------------------------------------------
                        DEVELOPED            UNDEVELOPED              TOTAL
                    ------------------     ---------------      ----------------
                     GROSS        NET      GROSS      NET       GROSS      NET
<S>                 <C>         <C>        <C>       <C>        <C>       <C>
Lobo Trend          20,676      11,554     8,206     5,516      28,882    17,070
Other                  640         640        --        --         640       640
                    ------      ------     -----     -----      ------    ------
  Total             21,316      12,194     8,206     5,516      29,522    17,710
                    ======      ======     =====     =====      ======    ======


                                                 1998
                    ------------------------------------------------------------
                        DEVELOPED            UNDEVELOPED              TOTAL
                    ------------------     ---------------      ----------------
                     GROSS        NET      GROSS      NET       GROSS      NET
<S>                 <C>         <C>        <C>       <C>        <C>       <C>
Lobo Trend          30,360      18,467     60,413    44,184     90,773    62,651
Other                2,585         394         --        --      2,585       394
                    ------      ------     ------    ------     ------    ------
  Total             32,945      18,861     60,413    44,184     93,358    63,045
                    ======      ======     ======    ======     ======    ======
</TABLE>

         Undeveloped acreage includes leased acres on which wells have not 
been drilled or completed to a point that would permit the production of 
commercial quantities of oil and natural gas, regardless of whether or not 
such acreage contains proved reserves. A gross acre is an acre in which an 
interest is owned. A net acre is deemed to exist when the sum of fractional 
ownership interests in gross acres equals one. The number of net acres is the 
sum of the fractional interests owned in gross acres expressed as whole 
numbers and fractions thereof.

DRILLING ACTIVITIES

         The table below sets forth the drilling activities of the Company on 
its properties for the years ended December 31, 1996, 1997 and 1998.

<TABLE>
<CAPTION>
                                                     YEAR ENDED DECEMBER 31,
                                  -----------------------------------------------------------
                                       1996                   1997                   1998
                                  -------------          -------------          -------------
                                  GROSS     NET          GROSS     NET          GROSS     NET
                                  -----     ---          -----     ---          -----     ---
<S>                               <C>       <C>          <C>      <C>           <C>      <C>
Development wells
  Productive Natural Gas            2       1.2            15      9.2           26      17.6
  Productive Oil                    0       0.0             0      0.0            0       0.0
  Dry                               0       0.0             4      2.5            6       4.7
Exploratory Wells
  Productive Natural Gas            0       0.0             0      0.0            0       0.0
  Productive Oil                    0       0.0             0      0.0            0       0.0
  Dry                               0       0.0             0      0.0            0       0.0
                                  ---       ---           ---     ----          ---      ----
    Total                           2       1.2            19     11.7           32      22.3
                                  ===       ===           ===     ====          ===      ====
Wells in progress at 
  end of period                     1       0.5             1      0.7            6       3.8
</TABLE>

         The information contained in the foregoing table should not be 
considered indicative of future performance, nor should it be assumed that 
there is any correlation between the number of productive wells drilled and 
the oil and natural gas reserves generated therefrom.

PRESENT ACTIVITIES

         From January 1, 1999 to March 15, 1999, the Company participated in 
drilling activities on a total of 7 gross (6 net) wells, 2 of which have been 
completed as productive wells, 3 of which were not completed and 2 of which 
were dry holes. 

         A dry well (hole) is an exploratory or development well found to be 
incapable of producing either oil or gas in sufficient quantities to justify 
completion as an oil and gas well. A productive well is an exploratory or 
development well that is not a dry hole.

TITLE TO PROPERTIES

         The Company believes it has satisfactory title to all of its 
producing properties in accordance with standards generally accepted in the 
oil and natural gas industry. The Company's properties are subject to 
customary royalty interests, liens incident to operating agreements, liens 
for current taxes and other burdens that the Company believes 

                                      12
<PAGE>

do not materially interfere with the use of or affect the value of such 
properties. Many of the Company's oil and natural gas properties are held in 
the form of mineral leases. The indebtedness under the Credit Facility is 
secured by substantially all of the Company's oil and natural gas properties. 
See Item 7 - "Management's Discussion and Analysis of Results of Operation 
and Financial Condition - Liquidity and Capital Resources" and "Financing 
Arrangements."

         As is customary in the oil and natural gas industry, a preliminary 
investigation of title is made at the time of acquisition of undeveloped 
properties. Title investigations, including a title opinion of local counsel, 
are generally completed, however, before commencement of drilling operations 
or the acquisition of producing properties. The Company believes that its 
methods of investigating title to, and acquiring, its oil and natural gas 
properties are consistent with practices customary in the industry and that 
it has generally satisfactory title to the leases covering its proved 
reserves.

GLOSSARY OF CERTAIN INDUSTRY TERMS

         The definitions set forth below shall apply to the indicated terms 
as used in this Annual Report on Form 10-K. All volumes of natural gas 
referred to herein are stated at the legal pressure base of the state or area 
where the reserves exist and at 60 degrees Fahrenheit and in most instances 
are rounded to the nearest major multiple.

         BBL. One stock tank barrel, or 42 U.S. gallons liquid volume, used 
herein in reference to crude oil or other liquid hydrocarbons.

         BBLS/D.  Stock tank barrels per day.

         BCF.  Billion cubic feet.

         BCFE. Billion cubic feet equivalent, determined using the ratio of 
six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas 
liquids.

         BTU. British thermal unit, which is the heat required to raise the 
temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

         CAPITAL ASSET. Under Section 1221 of the Internal Revenue Code of 
1986, as amended, a capital asset is defined as any type of property held by 
a taxpayer, but does not include, among other things; (1) stock in trade, 
property includible in inventory or property held primarily for sale to 
customers in the ordinary course of business; or (2) depreciable property 
used in a trade or business.

         DEVELOPED ACREAGE. The number of acres which are allocated or 
assignable to producing wells or wells capable of production.

         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.

         EXPLORATORY WELL. A well drilled to find and produce oil or natural 
gas reserves not classified as proved, to find a new reservoir in a field 
previously found to be productive of oil or natural gas in another reservoir 
or to extend a known reservoir.

         GROSS ACRES OR GROSS WELLS. The total acres or wells, as the case 
may be, in which a working interest is owned.

         MBBLS. One thousand barrels of crude oil or other liquid 
hydrocarbons.

         MBBLS/D. One thousand barrels of crude oil or other liquid 
hydrocarbons per day.

         MCF.  One thousand cubic feet.

         MCFE. One thousand cubic feet equivalent, determined using the ratio 
of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas 
liquids.

         MMBTU.  One million Btus.

                                      13
<PAGE>

         MMCF.  One million cubic feet.

         MMCF/D.  One million cubic feet per day.

         MMCFE. One million cubic feet equivalent, determined using the ratio 
of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas 
liquids, which approximates the relative energy content of crude oil, 
condensate and natural gas liquids as compared to natural gas. Prices have 
historically been higher or substantially higher for crude oil than natural 
gas on an energy equivalent basis.

         NET ACRES OR NET WELLS. The sum of the fractional working interests 
owned in gross acres or gross wells.

         PRESENT VALUE. When used with respect to oil and natural gas 
reserves, the estimated future gross revenue to be generated from the 
production of proved reserves, net of estimated future gross revenue to be 
generated from the production of proved reserves, net of estimated production 
and future development costs, using prices and costs in effect as of the date 
indicated, without giving effect to nonproperty-related expenses such as 
general and administrative expenses, debt service and future income tax 
expense or to depreciation, depletion and amortization, discounted using an 
annual discount rate of 10%.

         PROVED DEVELOPED RESERVES. Proved reserves that can be expected to 
be recovered from existing wells with existing equipment and operating 
methods.

         PROVED RESERVES. The estimated quantities of crude oil, natural gas 
and natural gas liquids that geological and engineering data demonstrate with 
reasonable certainty to be recoverable in future years from known reservoirs 
under existing economic and operating conditions.

         PROVED UNDEVELOPED LOCATION. A site on which a development well can 
be drilled consistent with spacing rules for purposes of recovering proved 
undeveloped reserves.

         PROVED UNDEVELOPED RESERVES. Reserves that are expected to be 
recovered from new wells on undrilled acreage, or from existing wells where a 
relatively major expenditure is required for recompletion; proved reserves 
for other undrilled units are claimed only where it can be demonstrated with 
certainty that there is continuity of production from the existing productive 
formation.

         PV-10 VALUE. When used with respect to oil and natural gas reserves, 
the estimated future gross revenue to be generated from the production of 
proved reserves, net of estimated production and future development costs, 
using prices and costs in effect as of the date indicated, without giving 
effect to nonproperty-related expenses such as general and administrative 
expenses, debt service and future income tax expense or to depreciation, 
depletion and amortization, discounted using an annual discount rate of 10%.

         RECOMPLETION. The completion for production of an existing well bore 
in another formation from that in which the well has been previously 
completed.

         RESERVOIR. A porous and permeable underground formation containing a 
natural accumulation of producible oil and/or natural gas that is confined by 
impermeable rock or water barriers and is individual and separate from other 
reservoirs.

         ROYALTY INTEREST. An interest in an oil and natural gas property 
entitling the owner to a share of oil or natural gas production free of costs 
of production.

         3-D SEISMIC. Advanced technology method of detecting geological 
structures susceptible to accumulations of hydrocarbons identified through a 
three-dimensional picture of the subsurface created by the collection and 
measurement of the intensity and timing of sound waves transmitted into the 
earth as they reflect back to the surface.

         UNDEVELOPED ACREAGE. Lease acreage on which wells have not been 
drilled or completed to a point that would permit the production of 
commercial quantities of oil and natural gas regardless of whether such 
acreage contains proved reserves.

         WORKING INTEREST. The operating interest that gives the owner the 
right to drill, produce and conduct operating activities on the property and 
a share of production.

                                      14
<PAGE>

         WORKOVER. Operations on a producing well to restore or increase 
production.

ITEM 3.  LEGAL PROCEEDINGS.

         From time to time the Company is a party to various legal 
proceedings arising in the ordinary course of business, but is not currently 
a party to litigation that it believes would have a material adverse effect 
on the consolidated financial condition, results of operations or cash flows 
of the Company.

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

         There were no matters submitted to a vote of security holders during 
the fourth quarter of 1998.

ITEM 5.  MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

         Michael Petroleum Corporation is a wholly owned subsidiary of 
Michael Holdings, Inc. ("MHI"). As of March 15, 1999, substantially all of 
common stock of MHI is owned by management, directors and employees of 
Michael Petroleum Corporation and thus no organized trading market exists for 
either the Company's or MHI's common stock. No dividends have been declared 
by the Company in the years ended December 31, 1997 and 1998. It is not 
anticipated by management of the Company that dividends will be declared in 
subsequent years. See "Item 12. Security Ownership of Certain Beneficial 
Owners and Management." The terms of the Indenture governing the Series B 
Notes and the Credit Facility restrict the Company's ability to declare and 
pay cash dividends.

ITEM 6.  SELECTED FINANCIAL DATA

       The following tables set forth selected consolidated financial data as 
of the end of each of the years in the five-year period ended December 31, 
1998. The financial data for each of the years ended, and as of, December 31, 
1994, 1995, 1996, 1997 and 1998 have been derived from the audited 
consolidated financial statements of the Company. This information should be 
read in conjunction with the Company's consolidated financial statements and 
Item 7. "Management's Discussion and Analysis of Financial Condition and 
Results of Operations." The Company's results of operations and financial 
condition have been affected by acquisitions of oil and natural gas 
properties during certain of the periods presented below. See Note 2 of Notes 
to Consolidated Financial Statements.

<TABLE>
<CAPTION>
                                                             YEAR ENDED DECEMBER 31,
                                             -------------------------------------------------------
                                              1994         1995       1996        1997        1998
                                             -------     -------     -------     -------     -------
                                                                  (IN THOUSANDS)
<S>                                          <C>         <C>         <C>         <C>         <C>
Income Statement Data:
Operating revenues                           $ 3,592     $ 2,937     $ 3,776     $ 9,139     $22,718
Operating expenses                             4,275       4,113       3,581       7,072      24,049
                                             -------     -------     -------     -------     -------
Operating income (loss)                         (683)     (1,176)        195       2,067      (1,331)
Loss from continuing operations                 (853)     (2,114)     (2,479)         (7)     (8,710)
Discontinued operations                         (719)      2,087           -           -           -
Extraordinary item                                 -           -           -           -        (531)
Net loss                                     $(1,572)    $   (27)    $(2,479)    $    (7)    $(9,241)
</TABLE>

                                       15
<PAGE>

<TABLE>
<CAPTION>                                                       AS OF DECEMBER 31,
                                             -------------------------------------------------------
                                              1994         1995       1996        1997        1998
                                             -------     -------     -------     -------     -------
                                                             (DOLLARS IN THOUSANDS)
<S>                                          <C>         <C>         <C>         <C>         <C>
Balance Sheet Data:
Current assets                               $ 1,611      $1,241     $ 4,375     $ 5,255     $  8,951
Oil and gas properties, net                    9,176       7,890      16,208      28,011      130,878
Total assets                                  11,461       9,145      21,001      33,617      147,282
Long-term debt                                 6,694       6,372      11,784      19,885      144,842
Shareholder's equity (deficit)                 1,111         423      (1,908)     (1,915)     (11,156)
</TABLE>


ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND 
FINANCIAL CONDITION

         The following discussion is intended to assist in an understanding 
of the Company's consolidated financial position and results of operations 
for each year during the three-year period ended December 31, 1998. The 
Company's consolidated financial statements and the notes thereto that follow 
contain detailed information that should be referred to in conjunction with 
the following discussion.

GENERAL

         The Company is an independent energy company engaged in the 
acquisition, exploitation and development of oil and natural gas properties, 
principally in the Lobo Trend of South Texas. The Company began operations in 
1983. In August 1996, the Company acquired interests in approximately 21,000 
developed and undeveloped gross acres in the Lobo Trend for approximately 
$15.3 million. In 1998, the Company acquired interests in approximately 
46,900 developed and undeveloped gross acres in the Lobo Trend for 
approximately $78.3 million. In 1998, the Company participated in the 
drilling of 32 gross and 22.3 net natural gas wells, completing 26 gross and 
17.6 net wells capable of commercial production, respectively.

         Through the periods presented, the Company's results of operations 
reflect two tax structures (S corporation and C corporation) which have 
influenced, among other things, the historical levels of its owners' 
compensation. Effective July 1, 1996, the Company changed its tax filing 
status from an S corporation to a C corporation. Due to this change, the 
Company recognized a one-time charge of approximately $2.0 million to reflect 
deferred income taxes payable as of June 30, 1996.

         The Company utilizes the "successful efforts" method of accounting 
for its oil and natural gas activities as described in Note 1 of Notes to 
Consolidated Financial Statements. From time to time, the Company has 
utilized hedging transactions with respect to a portion of its oil and 
natural gas production to achieve a more predictable cash flow, as well as to 
reduce its exposure to price fluctuations. See "Liquidity and Capital 
Resources."

RESULTS OF OPERATIONS

         The following table summarizes production volumes, average sales 
prices and operating revenues for the Company's oil and natural gas 
operations for the years ended December 31, 1996, 1997 and 1998:

<TABLE>
<CAPTION>
                                              YEAR ENDED DECEMBER 31
                                           -----------------------------
                                            1996       1997        1998 
                                           ------     ------     -------
                                              (DOLLARS IN THOUSANDS, 
                                               EXCEPT PER UNIT DATA)
<S>                                        <C>        <C>        <C>
Production volumes:
  Oil and condensate (MBbls)                   37         21          79
  Natural gas (Mmcf)                        1,324      3,685      10,510

Average sales prices:
  Oil and condensate (per Bbl)             $20.05     $18.95      $11.19
  Natural gas (per Mcf)                      2.15       2.33        2.07

Operating revenues:
  Oil and condensate                         $742       $565        $888
  Natural gas(1)                            2,852      8,574      21,780
                                           ------     ------     -------
    Total                                  $3,594     $9,139     $22,668
                                           ======     ======     =======
</TABLE>

(1)  Net of hedging gains or losses.

COMPARISON OF YEARS ENDED DECEMBER 31, 1998 AND 1997

                                      16
<PAGE>

         Oil and natural gas revenues for the year ended December 31, 1998 
increased 149% to $22.7 million from $9.1 million for the year ended December 
31, 1997. Production volumes for natural gas for the year ended December 31, 
1998 increased 185% to 10,510 Mmcf from 3,685 Mmcf for the year ended 1997. 
Average natural gas prices (including the effect of hedging transactions) 
decreased 12% to $2.07 per Mcf for 1998 from $2.33 per Mcf for 1997. The 
increase in natural gas production in 1998 was due to the Company's 1998 
acquisitions and the new wells placed on line resulting from the Company's 
drilling activities.

         Oil and natural gas production costs for the year ended December 31, 
1998 increased 116% to $4.1 million from $1.9 million for the year ended 
December 31, 1997, primarily due to the increase in production. However, 
actual production costs per equivalent unit decreased to $.37 per Mcfe for 
the year ended December 31, 1998 from $.57 per Mcfe for the year ended 
December 31, 1997. The decrease on an equivalent basis was due primarily to 
increased production volumes during 1998.

         Depletion, depreciation, and amortization ("DD&A") expense for the 
year ended December 31, 1998 increased 240% to $12.6 million from $3.7 
million for the same period in 1997. The increase in DD&A expense was due to 
higher production volumes and an increase in the depletion rate per Mcfe 
from $.96 for 1997 to $1.14 for 1998. The increase in rate was primarily due 
to acquisitions completed in 1998 and a reduction in estimated proved 
reserves. In addition, total impairment charges increased to $5.4 million for 
the year ended December 31, 1998 compared to $238,000 for the year ended 
December 31, 1997. The impairment charges in 1998 were primarily due to lower 
oil and natural gas prices and development dry holes drilled on certain oil 
and gas leases that resulted in a reduction in the estimated proved reserves.

         General and administrative expense increased 83% to $1.80 million in 
1998 from $980,000 for the same period in 1997 due to the addition of several 
new employees and their related benefits, plus increases in office expenses 
and legal and professional fees in connection with the Series A and Series B 
Notes offerings.

         Interest expense and loan amortization costs, net of capitalized 
interest, for the year ended December 31, 1998 increased 486% to $12.3 
million compared to $2.1 million for 1997. The increase was due to the higher 
levels of outstanding debt during 1998, primarily as a result of the Series A 
and Series B Notes offerings, as compared to 1997.

         The income tax benefit was $4.95 million for the year ended December 
31, 1998 compared to an income tax expense of $11,000 for the same period in 
1997. The Company has a net operating loss carryforward of $19.5 million at 
December 31, 1998 which was generated beginning in fiscal year 1997. The net 
operating loss will begin to expire in 2017. Thus, future taxable income of 
at least $19.5 million will need to be generated by 2017 in order for the 
Company to realize the net operating loss at December 31, 1998. Based on 
estimates of future taxable income, management believes it is more likely 
than not that the net operating loss will be fully utilized prior to 
expiration. In order to achieve sufficient taxable income, certain tax 
planning strategies (primarily the capitalization of intangible drilling 
costs for tax purposes) were implemented in fiscal year 1998. Specific 
differences between pre-tax loss and taxable income pertain to developmental 
dry holes, intangible drilling costs, capitalized interest and depletion and 
depreciation of oil and gas and other properties. Differences in these items 
begin reversing in fiscal year 1999 and thereafter. Estimates of future 
taxable income are significantly affected by changes in oil and natural gas 
prices, estimates of future production, and estimated operating and capital 
costs. The deferred tax asset could be reduced in the near term if 
management's estimates of taxable income during the carryforward period are 
significantly reduced or if alternative tax strategies are no longer viable. 
If the Company is not able to generate sufficient taxable income in the 
future through operating results, a valuation allowance will be recorded 
through a charge to expense. 

         The extraordinary loss of $531,000 (net of income tax benefit of 
$285,000) for the year ended December 31, 1998 was due to the writeoff of the 
remaining loan costs relating to the Company's credit agreement under the 
T.E.P. Financing, which terminated on April 2, 1998. No extraordinary charges 
or similar items occurred in 1997.

         The net loss for the year ended December 31, 1998 was $9.2 million 
compared to a loss of $7,000 for the year ended December 31, 1997, primarily 
as a result of the factors discussed above.

COMPARISON OF YEARS ENDED DECEMBER 31, 1997 AND 1996

         Oil and natural gas revenues for the year ended December 31, 1997 
increased 153% to $9.1 million compared to $3.6 million for 1996. Production 
volumes for natural gas during the year ended December 31, 1997 increased 
178% to 3,685 Mmcf from 1,324 Mmcf for 1996. Average gas prices increased 
8.3% to $2.33 per Mcf for 1997 from $2.15 per Mcf for 1996. The increase in 
natural gas production was due to the 1996 acquisitions and the Company's 
workover and drilling program with respect to the properties acquired and 
existing properties.

         Oil and natural gas production costs for the year ended December 31, 
1997 decreased 3% to $1.87 million from $1.93 million for 1996 primarily due 
to the sale of the Company's Hull Field oil properties in August 1996 that 
historically had incurred much higher lease operating costs than the 
Company's average Lobo Trend natural gas wells. Accordingly, production costs 
per equivalent unit decreased to $0.49 per Mcfe for 1997 from $1.25 per Mcfe 
for 1996. The per unit cost decreased as a result of increased production of 
natural gas, which has lower per unit operating costs, and the Company's 
disposition in August 1996 of oil producing properties having higher 
operating costs.

                                      17
<PAGE>

         DD&A expense for the year ended December 31, 1997 increased 208% to 
$3.7 million from $1.2 million for the same period in 1996. This increase was 
due to the increased production during 1997.

         Exploration expense increased from $46,000 in 1996 to $333,000 in 
1997, due primarily to the expiration of the terms of certain leases that had 
not been developed.

         General and administrative expense for the year ended December 31, 
1997 increased 131% to $980,000 from $424,000 for 1996, primarily as a result 
of increases in the number of employees and related benefits, plus increased 
legal and professional fees.

         Interest expense, net of capitalized interest, for the year ended 
December 31, 1997 increased 127% to $2.1 million, compared to $924,000 for 
1996. This increase in interest expense was due to increased debt levels in 
the second half of 1996 and in 1997 resulting from funds borrowed to acquire 
and develop the Lobo Trend properties.

         The net loss for the year ended December 31, 1997 decreased to 
$7,000, compared to a net loss of $2.5 million for 1996, as a result of the 
factors described above and the $2.0 million income tax charge related to the 
Company's conversion from an S corporation to a C corporation in 1996.

LIQUIDITY AND CAPITAL RESOURCES

         Cash flows provided by operating activities from the Company's 
operations were $848,000, $3.5 million and $5.3 million for the years ended 
December 31, 1996, 1997 and 1998, respectively. The increases in 1997 and 
1998 were primarily attributable to increased production resulting from the 
acquisitions and the new wells placed on line as a result of the Company's 
drilling activities. Cash and working capital in 1999 is expected to be 
provided through internally generated cash flows and borrowings. See 
"--Financing Arrangements" below.

         Cash flows used in investing activities by the Company were $14.8 
million, $15.0 million and $116.3 million in 1996, 1997 and 1998, 
respectively. Property additions through acquisition, exploration and 
development activities were the primary reasons for the use of funds in 
investing activities. Cash flows used in investing activities by the Company 
for 1996, 1997 and 1998 resulted primarily from the acquisition and 
development of the Lobo Trend properties.

         Cash flows provided by the Company's financing activities were $14.8 
million, $11.1 million and $110.7 in 1996, 1997 and 1998, respectively. In 
1996 and 1997, the cash flows from financing activities resulted from 
borrowings under the T.E.P. Financing. In 1998, the financing cash flows were 
primarily from proceeds from the Series A Notes and borrowings from the Credit 
Facility.

         The Company's primary sources of liquidity have historically been 
provided from funds generated by operations and from borrowings. The Company 
completed the sale of its $135.0 million Series A Notes in April 1998. 
Approximately $28.0 million of the net proceeds from the sale of the Series A 
Notes was used to repay the indebtedness outstanding under the T.E.P. 
Financing. Approximately $89.3 million of the net proceeds were used to fund 
acquisitions and the remaining balance for working capital and general 
corporate purposes. During May 1998, the Company entered into the Credit 
Facility, as described below under "--Financing Arrangements."

         The Company's revenues, profitability, future growth and ability to 
borrow funds and obtain additional capital, and the carrying value of its 
properties, are substantially dependent on prevailing prices of oil and 
natural gas. It is impossible to predict future oil and natural gas price 
movements with certainty. Declines in prices received for oil and natural gas 
would have an adverse effect on the Company's financial condition, liquidity, 
ability to finance capital expenditures and results of operations. Lower 
prices would also impact the amount of reserves that can be produced 
economically by the Company.

         During 1998, the Company recorded an impairment provision on 
producing properties of $5.4 million before income tax. This impairment 
provision was determined based on an assessment of recoverability of net 
property costs from estimated future net cash flows from those properties. 
Estimated future net cash flows are based on management's best estimate of 
projected oil and gas reserves and prices. If oil and gas prices remain at 
lower levels or decline further, the Company may be required to record 
further impairment provisions in the future, which may be material.

         The Company has experienced and expects to continue to experience 
substantial working capital requirements primarily due to the Company's 
development program. Capital expenditures for 1999 are currently estimated to 
be approximately $27.0 million. Substantially all of the capital expenditures 
will be used to fund drilling activities, property acquisitions and 3-D 
seismic surveys in the Company's project areas. The Company's plan 
anticipates drilling 32 gross (28 net) wells in 1999. However, the Company's 
borrowing base under its Credit Facility was reduced, effective April 1, 
1999, from $35 million to $23 million. The remaining amount of borrowing 
capacity under the Credit Facility was drawn as of April 1, 1999 to make the 
required interest payments on the Series B Notes. See "--Financing 
Arrangements" below. While the current estimates of capital expenditures for 
fiscal 1999 set forth above do not take into account this lower borrowing 
base, the Company believes that alternate sources of funding to finance the 
incremental capital expenditures that would otherwise be funded by the Credit 
Facility should be available to the Company. However, no assurances can be 
given that any such financing alternatives will be available, and if so, on 
terms considered advantageous to the Company. If suitable alternative 
financing or other alternative capital resources are not available to the 
Company, its currently planned capital expenditures would be reduced and 
could be significantly reduced. See "--Cautionary Statements Regarding 
Forward-Looking Information-Future Need For and Availability of Capital," 
"--Restrictions Imposed by Lenders" and "--Incurrence of Substantial 
Indebtedness."

         Assuming additional debt financing was available to fund the 
Company's 1999 estimated capital expenditures level, the Company believes 
that additional financing, preferably public or private equity financing, 
will be necessary in the future in order for the Company to continue to 
increase its reserve base and make additional acquisitions in accordance with 
its long-range development plan. Should recent prevailing equity market 
conditions for oil and natural gas independent exploration and development 
companies continue, the Company does not foresee an infusion of funds from 
public sales of its equity for the foreseeable future. An inability to obtain 
sufficient capital to achieve these purposes could cause the Company to 
curtail its planned property acquisition and development activities, which 
could adversely affect its future financial condition, cash flows and results 
of operations.


                                      18
<PAGE>

FINANCING ARRANGEMENTS

         In August 1996, the Company entered into the T.E.P. Financing, which 
provided for an aggregate term loan amount of $42.2 million, available for 
oil and natural gas property acquisitions and development drilling, subject 
in each case to borrowing base limitations. The Company used approximately 
$28.0 million of the net proceeds from the sale of the Series A Notes to 
repay all of the outstanding indebtedness under the T.E.P. Financing in April 
1998.

         In August 1996, the Company also granted Cambrian Capital Partners, 
L.P., an affiliate of the T.E.P. Financing lender ("Cambrian"), a 30% Net 
Profits Interest (as defined in the Net Profits Interest Conveyance dated 
August 12, 1996), net to the Company's interest, in all of the Company's 
properties, including those acquired in the 1996 Acquisition. As part of the 
T.E.P. Financing, the Company also granted to Cambrian a warrant to purchase 
up to 5% of the Company's common stock until August 12, 2001. The value 
assigned to the Net Profits Interest and warrant was recorded as a discount 
to the loan proceeds. The Company used approximately $11.0 million of the net 
proceeds from the sale of the Series A Notes to acquire the Net Profits 
Interest. In addition, the warrant to purchase the Company's common stock was 
cancelled, and MHI issued to Cambrian a warrant to acquire 38,671 shares of 
its Common Stock at an exercise price of $8.00 per share.

         In May 1998, the Company entered into its Credit Facility with 
Christiania as lender and administrative agent, pursuant to the terms of the 
Credit Facility. The Credit Facility provided for loans in an outstanding 
principal amount not to exceed $50.0 million at any one time, subject to a 
borrowing base to be determined semi-annually (each April and October) by the 
administrative agent (the initial borrowing base was $30.0 million), and the 
issuance of letters of credit in an outstanding face amount not to exceed 
$6.0 million at any one time with the face amount of all outstanding letters 
of credit reducing, dollar-for-dollar, the availability of loans under the 
Credit Facility. Although the initial borrowing base was $30 million, and 
effective November 9, 1998, the borrowing base was increased by $5 million to 
a total of $35 million, the new borrowing base effective April 1, 1999, was 
reduced to $23 million. See "--Liquidity and Capital Resources" above.

         Under the Credit Facility, the principal balance outstanding is due 
and payable on May 28, 2002, and each letter of credit shall be reimbursable 
by the Company when drawn, or if not then otherwise reimbursed, paid pursuant 
to a loan under the Credit Facility. Commencing on October 31, 1999, and 
continuing until its stated maturity, the maximum amount available for 
borrowings and letters of credit under the Credit Facility will not only be 
adjusted (increased or decreased, as applicable) by the semi-annual borrowing 
base determination, but also (i) decreased by monthly mandatory reductions in 
the borrowing base of $1.5 million per month and (ii) adjusted for sales of 
collateral having an aggregate value exceeding the lesser of $4.0 million per 
year or 5% of the Company's total proved reserve values. At March 31, 1999, 
the Company had drawn all of the $23 million then available under Credit 
Facility. Both the Company and Christiania may also initiate two unscheduled 
redeterminations of the borrowing base during any consecutive twelve-month 
period. If the sum of the outstanding principal balance and amount of 
outstanding letters of credit (both drawn and undrawn) exceeds the borrowing 
base, the Company shall, within 30 days, either repay such excess in full or 
provide additional collateral acceptable to Christiania.

         The Credit Agreement contains certain covenants by the Company, 
including (i) limitations on additional indebtedness and on guaranties by the 
Company except as permitted under the Credit Agreement, (ii) limitations on 
additional investments except those permitted under the Credit Agreement and 
(iii) restrictions on dividends or distributions or on repurchases or 
redemptions of capital stock by the Company except for those involving 
repurchases of MHI capital stock which may not exceed $500,000 in any fiscal 
year. In addition, the Credit Agreement requires the Company to maintain and 
comply with certain financial covenants and ratios, including a minimum 
interest coverage ratio, a minimum current ratio and a covenant requiring 
that the Company's general and administrative expenses may not exceed 12.5% 
of the Company's gross revenues in any calendar year. As of December 31, 
1998, the Company was in violation of certain administrative covenants and a
financial covenant under the Credit Facility. The Company has obtained a 
waiver with respect to these violations from Christiania, which agreed not to 
assert any default based upon such violations. The Company and the lender 
have entered into a First Amendment to the Credit Facility to amend those 
covenants and the interest rate under the Credit Facility.

         As amended, the interest rate for each borrowing under the Credit 
Facility will be calculated at either (i) the ABR rate (as described below), 
or (ii) the Eurodollar Rate (as described below) plus 2.25%, at the election 
of the Company. Interest on the borrowings under the Credit Facility will be 
due (i) with respect to loans bearing interest at the ABR rate, quarterly in 
arrears and at maturity, and (ii) with respect to loans bearing interest at 
the Eurodollar Rate, on the last day of each relevant interest period and, in 
the case of any interest period longer than three months, on a quarterly 
basis. The Company's obligations under the Credit Facility are secured by 
substantially all of the oil and natural gas assets of the Company, including 
accounts receivable and material contracts, equipment and gathering systems. 
The proceeds of the Credit Facility may be used to finance working capital 
needs and for general corporate purposes of the Company in the ordinary 
course of its business.

         Under the Credit Facility, "ABR" means the highest of (i) the 
interest rate announced publicly by Christiania as its prime rate plus 0.5% 
in effect in its principal office in New York, (ii) the secondary market rate 
for three-month certificates of deposit (adjusted for statutory reserve 
requirements) plus 1.5% and (iii) the federal funds effective rate from time 
to time plus 1.0%. "Eurodollar Rate" means the rate (adjusted for statutory 
reserve requirements of eurocurrency 

                                      19
<PAGE>

liabilities) at which eurodollar deposits for one, two, three or six (or, if 
available and acceptable to the Credit Facility lenders, nine or twelve) 
months (as selected by the Company) are offered to Christiania in the 
Interbank eurodollar market.

         See "--Cautionary Statements Regarding Forward-Looking Information-
Future Need For and Availability of Capital," "--Restrictions Imposed by 
Lenders" and "--Incurrence of Substantial Indebtedness."

TERMS AND FINANCIAL COVENANTS OF 11 1/2% SENIOR NOTES DUE 2005

         The indenture governing the Series B Notes (the "Indenture") contains 
certain covenants that, among other things, limit the ability of the Company 
to incur additional indebtedness, pay dividends, repurchase equity interests 
or make other Restricted Payments (as defined in the Indenture), create 
liens, enter into transactions with affiliates, sell assets or enter into 
certain mergers and consolidations. The Company is allowed to incur 
additional indebtedness if it meets an EBITDA/Interest ratio and an 
ACNTA/Debt ratio computed based on the last four quarters immediately 
proceeding the incurrence of the indebtedness on a pro forma basis. In the 
event of certain asset dispositions, the Company is required under certain 
circumstances to use the excess proceeds from such a disposition to offer to 
repurchase the Series B Notes (and other Senior Indebtedness for which an offer
to repurchase is required to be concurrently made) having an aggregate 
principal amount equal to the excess proceeds at a purchase price equal to 
100% of the principal amount of the Series B Notes, together with accrued and 
unpaid interest and Liquidated Damages (as defined in the Indenture), if any, 
to the date of repurchase (a "Net Proceeds Offer").

CAPITAL EXPENDITURES AND OUTLOOK

         The following table sets forth the Company's capital expenditures 
for the three years ended December 31, 1998 (in thousands):

<TABLE>
<CAPTION>
                                       YEAR ENDED DECEMBER 31
                                -----------------------------------
                                  1996         1997          1998
                                --------     --------      --------
<S>                             <C>          <C>           <C>
Property acquisition:
  Unproved                      $  2,929     $    355      $ 15,183
  Proved                           9,554        2,425        78,458
Development                        2,757       12,074        25,295
Interest capitalized                 217          574         1,440
                                --------     --------      --------
    Total costs incurred        $ 15,457     $ 15,428      $120,376
                                ========     ========      ========
</TABLE>

         The Company currently has budgeted capital expenditures of 
approximately $27.0 million for 1999. See "--Liquidity and Capital Resources" 
above. Substantially all of the capital expenditures will be used to fund 
drilling activities, property acquisitions and 3-D seismic surveys in the 
Company's project areas. The Company intends to drill approximately 32 gross 
(28 net) wells in 1999. The Company will require capital from sources in 
addition to that funded under the Credit Facility in order for the Company to 
fully implement its development drilling strategy in 1999 and for the 
foreseeable future. In the event that additional capital is not available to 
the Company, capital expenditures are expected to be reduced and could be 
significantly reduced.

         NATURAL GAS BALANCING

         The Company incurs certain natural gas production volume imbalances 
in the ordinary course of business and utilizes the sales method to account 
for such imbalances. Under this method, income is recorded based on the 
Company's net revenue interest in production taken for delivery. Management 
does not believe that the Company had any material imbalances as of December 
31, 1996, 1997, or 1998.

EFFECTS OF INFLATION AND CHANGES IN PRICE

                                      20
<PAGE>

         The Company's results of operations and cash flows are affected by 
changes in oil and natural gas prices. If the price of oil and natural gas 
increases (decreases), there could be a corresponding increase (decrease) in 
the operating cost that the Company is required to bear for operations, as 
well as an increase (decrease) in revenues. Inflation has had only a minimal 
effect on the Company.

YEAR 2000

         Many computer systems have been designed using software that 
processes transactions using two digits to represent the year. This type of 
software will generally require modifications to function properly with dates 
after December 31, 1999. The same issue applies to microprocessors embedded 
in machinery and equipment, such as gas compressors and pipeline meters. The 
impact of failing to identify and correct this problem could be significant 
to the Company's ability to operate and report results, as well as 
potentially exposing the Company to third party liability.

         The Company has begun making necessary modifications to its internal 
information computer systems in preparation for the Year 2000. The Company 
currently estimates that its Year 2000 project will be completed by June 
1999, and believes that the total related costs will be approximately 
$30,000, funded by cash from operations or short term borrowings. Actual 
costs to date have been less than $10,000.

         The Company began reviewing the Year 2000 compliance status of field 
equipment, including compressor stations, gas control systems and data 
logging equipment, during the fourth quarter of 1998 and expects to complete 
this review by June 1999.

         The Company has identified significant third parties whose Year 2000 
compliance could affect the Company and is in the process of formally 
inquiring about their Year 2000 status. The Company has received responses to 
less than 10% of its inquiries. Despite its efforts to assure that such 
third parties are Year 2000 compliant, the Company cannot provide assurance 
that all significant third parties will achieve compliance in a timely 
manner. A third party's failure to achieve Year 2000 compliance could have a 
material adverse effect on the Company's operations and cash flow. The 
potential effect of Year 2000 non-compliance by third parties is currently 
unknown.

         Project costs and the timetable for Year 2000 compliance are based 
on management's best estimates. In developing these estimates, assumptions 
were made regarding future events including, among other things, the 
availability of certain resources and the continued cooperation of the 
Company's customers and suppliers. Actual costs and timing may differ from 
management's estimates due to unexpected difficulties in obtaining trained 
personnel, locating and correcting relevant computer code and other factors. 
Management does not expect the costs of the Company's Year 2000 project to 
have a material adverse effect on the Company's financial position, results 
of operations or cash flows. Presently, based on information available, the 
Company cannot conclude that any failure of the Company or third parties to 
achieve Year 2000 compliance will not adversely effect the Company.

         The Company has designated personnel responsible to not only 
identify and respond to these issues, but also to develop a contingency plan 
in the event that a problem arises after the turn of the century.The Company 
is currently identifying appropriate contingency plans in the event of 
potential problems resulting from failure of the Company's or significant 
third party computer systems on January 1, 2000. The Company has not 
completed any contingency plans to date. Specific contingency plans will be 
developed in response to the results of testing scheduled to be complete by 
October 1999, as well as the assessed probability and risk of system or 
equipment failure. These contingency plans may include installing backup 
computer systems or equipment, temporarily replacing systems or equipment 
with manual processes, and identifying alternative suppliers, service 
companies and purchasers. The Company expects these plans to be complete by 
December 1999.

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION

         Certain information contained in this Annual Report on Form 10-K (as 
well as certain other written or oral statements made by or on behalf of the 
Company) may be deemed to be forward-looking statements which can be 
identified by the use of forward-looking terminology such as "believes," 
"expects," "may," "will," "should" or "anticipates" or the negative thereof 
or comparable terminology, or by discussions of strategy that involve risks 
and uncertainties. In addition, all statements other than statements of 
historical facts included in this Annual Report on Form 10-K, including, 
without limitation, statements regarding the the levels of capital 
expenditures for 1999 and succeeding periods, the availability of sources of 
capital to fund these capital expenditures and the Company's other working 
capital and operational requirements, the Company's business strategy, 
worldwide prices for crude oil and natural gas, the Company's ability to 
raise additional long-term capital, the Company's success in dealing with its 
lenders, future governmental regulation, future oil and natural gas reserves, 
future drilling and development opportunities and operations, future 
acquisitions, future production of oil and natural gas (and the prices 
thereof and costs therefor), anticipated results of hedging activities, 
future capital expenditures and future net cash flows, are forward-looking 
statements and may contain information concerning financial results, economic 
conditions, trends and known uncertainties. Such statements reflect the 
Company's current views with respect to future events and financial 
performance, and involve risks and uncertainties. Actual results could differ 
materially from those projected in the forward-looking statements as a result 
of these various risks and uncertainties, including, without limitation, (i) 
factors discussed below such as natural gas price fluctuations and markets, 
uncertainties of estimates of reserves and future net revenues, the success 
of the Company's drilling programs, competition in the oil and natural gas 
industry, operating risks, risks associated with acquisitions, future need 
for and availability of capital, and regulatory and environmental risks, (ii) 
adverse changes to the properties acquired in the Transactions and the 
interests subject to the Lobo Lease or the failure of the Company to achieve 
the anticipated benefits of the Transactions and the interests subject to the 
Lobo Lease, (iii) adverse changes in the market for the Company's oil and 
natural gas production and (iv) those additional factors discussed 
immediately below and under Item 7. "Management's Discussion and Analysis of 
Financial Condition and Results of Operations," Item 1. "Business" and Item 2.
"Properties" and elsewhere in this Annual Report on Form 10-K. 

INCURRENCE OF SUBSTANTIAL INDEBTEDNESS

         As of December 31, 1998, the Company had $147.1 million ($144.8 
million, net of unamortized discount) of indebtedness outstanding (including 
current maturities of long-term indebtedness) as compared to a shareholder's 
deficit of $11.2 million. The indenture limits the amounts of borrowings 
under bank facilities, including borrowings under the Credit Facility. In 
addition, as of March 31, 1999, due to borrowing base reductions, the Company 
has no borrowing capacity remaining under the Credit Facility. See Item 7. 
"Management's Discussion and Analysis of Financial Condition and Results of 
Operations--Liquidity and Capital Resources" and "--Financing Arrangements".

         This level of indebtedness may pose substantial risks to the 
Company, including, but not limited to, the following: (i) the Company's 
ability to obtain additional financing in the future, whether for working 
capital, capital expenditures, acquisitions or other purposes, may be 
impaired; (ii) a portion of the Company's cash flow from operations is 
required to be dedicated to the payment of interest on its debt, thereby 
reducing funds available to the Company for other purposes; (iii) the Company 
may not generate sufficient cash flow to pay the principal of and interest on 
the Series B Notes; (iv) the Company's flexibility in planning for or 
reacting to changes in market conditions may be limited; and (v) the Company 
may be more vulnerable given current prevailing industry conditions. In 
addition, the Company's earnings have been insufficient to meet its fixed 
charges.

         The ability of the Company to meet its debt service obligations, 
including with respect to the Series B Notes, will depend on the future 
operating performance and financial results of the Company, which will be 
subject in part to factors beyond the control of the Company. Further, if the 
Company is unsuccessful in increasing its proved reserves, the future net 
revenues from existing proved reserves may not be sufficient to pay the 
principal of and interest on the 

                                      21
<PAGE>

Series B Notes in accordance with their terms. There can be no assurance that 
the Company will continue to generate earnings in the future sufficient to 
cover its fixed charges. If the Company is unable to generate earnings in the 
future sufficient to cover its fixed charges and is unable to borrow 
sufficient funds to cover such charges, it may be required to refinance all 
or a portion of its debt or to sell all or a portion of its assets. There can 
be no assurance that a refinancing would be possible, nor can there be any 
assurance as to the timing of any asset sales or the proceeds that the 
Company could realize therefrom. In addition, the Credit Agreement contains 
certain covenants by the Company, including (i) limitations on additional 
indebtedness and on guaranties by the Company except as permitted under the 
Credit Agreement, (ii) limitations on additional investments except those 
permitted under the Credit Agreement and (iii) restrictions on dividends or 
distributions on or repurchases or redemptions of capital stock by the 
Company, except for those involving repurchases of MHI capital stock which 
may not exceed $500,000 in any fiscal year. Also, the Credit Agreement 
requires the Company to maintain and comply with certain financial covenants 
and ratios, including a minimum interest coverage ratio, a minimum current 
ratio and a covenant requiring that the Company's general and administrative 
expenses may not exceed 12.5% of the Company's gross revenues in any calendar 
year. See "--Restrictions Imposed by Lenders," "--Future Need for and 
Availability of Capital" and Item 7. "Management's Discussion and Analysis of 
Financial Condition and Results of Operations--Financing Arrangements."

EFFECTIVE SUBORDINATION OF THE SERIES B NOTES

         The Series B Notes are senior unsecured obligations of the Company 
and rank in parity with all existing and future Senior Indebtedness of the 
Company, including any indebtedness incurred under the Credit Facility, and 
senior in right of payment to all future Subordinated Indebtedness of the 
Company. Holders of secured Indebtedness of the Company, including under the 
Credit Facility, will have claims with respect to assets constituting 
collateral for such Indebtedness that are prior to the claims of the Holders 
of the Series B Notes. In the event of a default on the Series B Notes, or a 
bankruptcy, liquidation or reorganization of the Company, such assets will be 
available to satisfy obligations with respect to the indebtedness secured 
thereby before any payment therefrom could be made on the Series B Notes. 
Accordingly, the Series B Notes will be effectively subordinated to claims of 
secured creditors of the Company to the extent of such pledged collateral. As 
of March 31, 1999, the Company had $23.0 million of secured indebtedness.

RESTRICTIONS IMPOSED BY LENDERS

         The Indenture and the Credit Agreement governing the terms of the 
Credit Facility impose significant operating and financial restrictions on 
the Company. Such restrictions will affect, and in many respects 
significantly limit or prohibit, among other things, the ability of the 
Company to incur additional indebtedness, make certain capital expenditures, 
pay dividends, repay or repurchase indebtedness prior to its stated maturity 
or engage in mergers or acquisitions. These restrictions could also limit the 
ability of the Company to effect future financings, make needed capital 
expenditures, withstand a future downturn in the Company's business or the 
economy in general, or otherwise conduct necessary corporate activities. Any 
failure by the Company to comply with these restrictions could lead to a 
default under the terms of such indebtedness and the Series B Notes. In the 
event of default, the holders of such indebtedness could elect to declare all 
of the funds borrowed pursuant thereto to be due and payable together with 
accrued and unpaid interest. In such event, there can be no assurance that 
the Company would be able to make such payments or borrow sufficient funds 
from alternative sources to make any such payment. Even if additional 
financing could be obtained, there can be no assurance that it would be on 
terms that are favorable or acceptable to the Company. In addition, the 
Company's indebtedness under the Credit Facility is secured by a substantial 
oprtion of the assets and properties of the Company. The pledge of such 
collateral to the Company's secured lenders could impair the Company's 
ability to obtain additional financing on favorable terms. See Item 7. 
"Management's Discussion and Analysis of Financial Condition and Results of 
Operations--Liquidity and Capital Resources" and "--Financing Arrangements."

FUTURE NEED FOR AND AVAILABILITY OF CAPITAL

         The Company anticipates that it will require additional financing to 
effect both future property acquisitions and continue its development 
programs. The Company or MHI may seek funds through the sale of debt or 
equity securities, which could significantly dilute the ownership of the 
Company's or MHI's existing shareholders. In addition, if necessary (and 
permitted under the terms of the indenture), the Company or MHI may seek 
funds from project financing, strategic alliances or other sources, all of 
which may dilute the interest of the Company in the specific project 
financed. The Company's ability to access additional capital is dependent 
upon the Company's outstanding commitments and financial condition, and the 
financial strength of the capital markets at such time. There can be no 
assurance that such additional financing can be obtained 

                                      22
<PAGE>

or, if so, obtained on terms acceptable to the Company.

         Future cash flows and the availability of credit are subject to a 
number of variables, such as the level of production from existing wells, 
prices of oil and natural gas and the Company's success in locating and 
producing new reserves. If revenues were to decrease as a result of lower oil 
and natural gas prices, decreased production or otherwise, the Company could 
have limited ability to replace its reserves or to maintain production at 
current levels, resulting in a decrease in production and revenues over time. 
The Company has budgeted approximately $27.0 million for capital expenditures 
in 1999, exclusive of acquisitions. The Company expects to use cash flow from 
operations and from borrowings or other capital sources to fund these 
expenditures. However, the Company's borrowing base under the Credit Facility 
has been reduced from $35 million to $23 million, substantially all of which 
is currently drawn. If the Company's cash flow from operations and 
availability of funds from other capital sources are not sufficient to 
satisfy its capital expenditure requirements capital expenditures may be 
reduced. There can be no assurance that additional debt or equity financing 
will be available. See "Item 7. Management's Discussion and Analysis of 
Financial Condition and Results of Operations--Liquidity and Capital Resources."

VOLATILITY OF NATURAL GAS AND OIL PRICES

         The revenues generated by the Company's operations are highly 
dependent upon the prices of, and demand for, natural gas and, to a lesser 
extent, the price of oil. Historically, the prices of oil and natural gas 
have been volatile and are likely to continue to be volatile in the future 
and are dependent upon numerous factors such as weather, domestic and foreign 
political and economic conditions, the overall level of international and 
domestic demand for oil and natural gas, domestic and international 
regulatory developments, domestic and international severance and excise 
taxes, competition from other sources of energy and the availability of 
pipeline capacity. The Company is affected more by fluctuations in natural 
gas prices than oil prices, because the majority of its production is natural 
gas. The volatile nature of the energy markets and the unpredictability of 
actions of OPEC members make it impossible to predict future prices of 
natural gas and oil with any certainty. Prices of natural gas and oil are 
subject to wide fluctuations in response to relatively minor changes in 
circumstances, and there can be no assurance that future prolonged decreases 
in such prices will not occur. All of these factors are beyond the control of 
the Company. Any significant decline in natural gas and oil prices would have 
a material adverse effect on the Company's results of operations and 
financial condition, its ability to fund operations and capital expenditures, 
the book value of its natural gas and oil properties and its ability to meet 
its debt service requirements. Although the Company may enter into hedging 
arrangements from time to time to reduce its exposure to price risks in the 
sale of its natural gas and oil, substantially all of the Company's 
production will remain subject to natural gas and oil price fluctuations. 

DEPENDENCE ON DISTRIBUTION AND PROCESSING SYSTEMS

         The marketability of the Company's natural gas and oil production 
depends upon the availability and capacity of natural gas gathering systems, 
pipelines and processing facilities which are not owned by the Company. The 
unavailability or lack of capacity thereof could result in the shut-in of 
producing wells or the delay or discontinuance of development plans for 
properties. Moreover, substantially all of the Company's properties rely on 
the same gathering systems, transportation lines and processing plants. In 
addition, federal and state regulation of oil and natural gas production and 
transportation, general economic conditions and changes in supply and demand 
could adversely affect the Company's ability to produce and market its 
natural gas and oil on a profitable basis. Any significant change in the 
Company's ability to market its production could have a material adverse 
effect on the Company's financial condition and results of operations.

CONCENTRATION OF PRODUCING PROPERTIES

         The Company's production of natural gas and oil is concentrated 
within an approximate 120 square mile area in the Lobo Trend. Any impairment 
or material reduction in the expected size of the reserves attributable to 
the Company's wells, any material harm to the producing reservoirs from which 
these wells produce or any significant governmental regulation with respect 
to any of these wells, including curtailment of production or interruption of 
transportation of production, could have a material adverse effect on the 
Company's financial condition and results of operations.

DRILLING RISKS

         The Company's revenues, operating results and future rate of growth 
will be dependent upon the success of its drilling program. Oil and natural 
gas drilling involves numerous risks, including the risk that no commercially 
productive oil or natural gas reservoirs will be encountered. The timing and 
cost of drilling, completing and operating wells is often uncertain, and 
drilling 

                                      23
<PAGE>

operations may be curtailed, delayed or canceled as a result of a variety of 
factors, including unexpected drilling conditions, pressure or irregularities 
in formations, equipment failures or accidents, adverse weather conditions, 
compliance with governmental requirements and shortages or delays in the 
availability of drilling rigs and the delivery of equipment. Oil and natural 
gas drilling remains a speculative activity notwithstanding the Company's use 
of 3-D seismic data. Even when fully utilized and properly interpreted, 3-D 
seismic data and other advanced technologies only assist geoscientists in 
identifying subsurface structures and do not enable the interpreter to know 
whether hydrocarbons are in fact present in such structures. In addition, the 
use of 3-D seismic data and other advanced technologies requires greater 
predrilling expenditures than traditional drilling strategies and the Company 
could incur losses as a result of such expenditures. Furthermore, completion 
of a well does not assure a profit on the investment or a recovery of any 
portion of drilling, completion or operating costs.

         Unsuccessful drilling activities could have a material adverse 
effect on the Company's results of operations and financial condition. There 
can be no assurance that the Company's overall drilling success rate or its 
drilling success rate within a particular project area will not decline. The 
Company may choose not to acquire option and lease rights prior to acquiring 
seismic data and, in many cases, the Company may identify a prospect or 
drilling location before seeking option or lease rights in the prospect or 
location. Although the Company has identified or budgeted for numerous 
drilling prospects, there can be no assurance that such prospects will ever 
be leased or drilled (or drilled within the scheduled or budgeted time frame) 
or that oil or natural gas will be produced from any such prospects or any 
other prospects. In addition, prospects may initially be identified through a 
number of methods, some of which do not include interpretation of 3-D or 
other seismic data. Actual drilling and results are likely to vary from such 
statistical results and such variance may be material. Similarly, the 
Company's drilling schedule may vary from its capital budget because of 
future uncertainties, including those described above. See Item 7. "Management's
Discussion and Analysis of Financial Condition and Results of Operations."

ABILITY AND NEED TO REPLACE RESERVES

         The Company's future success depends upon its ability to find, 
develop or acquire additional oil and natural gas reserves that are 
economically recoverable. Unless the Company successfully replaces the 
reserves that it produces through successful development, exploration or 
acquisition, the Company's proved reserves will decline. Further, 
substantially all of the Company's estimated proved reserves at December 31, 
1998 were located in the Lobo Trend, where wells are characterized by high 
initial production followed by rapid initial decline rates and a relative 
flattening of production thereafter. Additionally, approximately 61.3% of the 
PV-10 Value of the Company's total estimated proved undeveloped reserves as 
of December 31, 1998 was attributable to undeveloped reserves. Recovery of 
such reserves will require significant capital expenditures and successful 
drilling operations, and there can be no certainty regarding the results of 
developing these reserves. The Company's business strategy is to add reserves 
by pursuing an active development drilling program on its properties 
(including the properties acquired in the Transactions) and on additional 
properties that it may acquire in the future. There can be no assurance that 
the Company will drill the number of wells currently projected or that the 
production from these new wells will be sufficient to replace production from 
existing wells during such period. To the extent the Company is unsuccessful 
in replacing or expanding its estimated proved reserves, the Company may be 
unable to pay the principal of and interest on the Series B Notes in 
accordance with their terms, or otherwise to satisfy certain of its covenants 
contained in the Indenture.

UNCERTAINTY OF ESTIMATES OF RESERVES AND FUTURE NET REVENUES

         The proved developed and undeveloped oil and natural gas reserve 
data presented in this Report are estimates based on reserve reports 
prepared by independent petroleum engineers, as well as internally generated 
reports by the Company. The estimation of reserves requires substantial 
judgment on the part of the petroleum engineers, resulting in imprecise 
determinations, particularly with respect to new discoveries. Estimates of 
economically recoverable oil and natural gas reserves and of future net 
revenues necessarily depend upon a number of variable factors and 
assumptions, such as assumed production, which is based in part on an 
assessment of historical production from the area compared with production 
from other producing areas, the assumed effects of regulations by 
governmental agencies and assumptions concerning future oil and natural gas 
prices, future operating costs, severance and excise taxes, capital 
expenditures and workover and remedial costs, all of which may in fact vary 
considerably from actual results. Estimates of reserves and of future net 
revenues prepared by different petroleum engineers may vary substantially, 
depending, in part, on the assumptions made (including assumptions required 
by the SEC), as to oil and natural gas prices, drilling, workover, remedial 
and operating expenses, capital expenditures, severance and ad valorem taxes 
and availability of funds, and may be subject to material adjustment. 
Estimates of proved undeveloped reserve quantities, which comprise 73% of the 
Company's total proved reserves as of December 31, 1998, are, by their nature, 

                                      24
<PAGE>

much less certain than proved developed reserves. The accuracy of any reserve 
estimate depends on the quality of available data as well as engineering and 
geological interpretation and judgment. Results of drilling, testing and 
production or price changes subsequent to the date of the estimate may result 
in changes to such estimates. Any significant variance in the assumptions 
could materially affect estimates of 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. The estimates of future net 
revenues contained herein reflect oil and natural gas prices and production 
costs as of the date of estimation, without escalation, except where changes 
in prices were fixed under existing contracts. There can be no assurance that 
such prices will be realized, estimated production volumes will be produced 
or proved undeveloped reserves will be developed during the period specified 
in such reports. Either inaccuracies in estimates of proved undeveloped 
reserves or the inability to fund development could result in substantially 
reduced reserves. In addition, the timing of receipt of estimated future net 
revenues from proved undeveloped reserves will be dependent upon the timing 
and implementation of drilling and development activities estimated by the 
Company for purposes of the reserve report. See "Item 2. Properties--Oil and 
Natural Gas Reserves." The estimated reserves and future net revenues may be 
subject to material downward or upward revision based upon production 
history, results of future development, prevailing oil and natural gas prices 
and other factors. A material decrease in estimated reserves or future net 
revenues could have a material adverse effect on the Company's financial 
condition and results of operations.

         In addition, the PV-10 Value of the Company's proved oil and natural 
gas reserves does not necessarily represent the current or fair market value 
of such proved reserves, and the 10% discount rate required by the SEC may 
not reflect current interest rates, the Company's cost of capital or any 
risks associated with the development and production of the Company's proved 
oil and natural gas reserves. In accordance with applicable SEC requirements, 
proved reserves and the future net revenues from which PV-10 Value is derived 
are estimated using prices and costs at the date of the estimate held 
constant throughout the life of the properties (except to the extent a 
contract specifically provides otherwise). The Company emphasizes with 
respect to such estimates that the discounted future net cash flows should 
not be construed as representative of the fair market value of the proved oil 
and natural gas properties belonging to the Company, because discounted 
future net cash flows are based upon projected cash flows that do not provide 
for changes in oil and natural gas prices or for escalation of expenses and 
capital costs. The meaningfulness of such estimates is highly dependent upon 
the accuracy of the assumptions upon which they were based. Actual results 
may differ materially from the results estimated. The estimated future net 
revenues attributable to the Company's proved oil and natural gas reserves 
are based on prices in effect at December 31, 1998 ($1.85 per Mcf of natural 
gas and $9.17 per Bbl of oil), which may be materially different than actual 
future prices. See "Item 2. Properties--Oil and Natural Gas Reserves."

RISKS ASSOCIATED WITH ACQUISITIONS

         The successful acquisition of producing properties requires an 
assessment of recoverable reserves, future oil and natural gas prices, 
operating costs, potential environmental and other liabilities and other 
factors. Such assessments are necessarily inexact. In connection with its 
assessment of a potential acquisition, the Company performs a review of the 
subject properties that it believes to be generally consistent with industry 
practices, including examination of contingencies associated with the 
properties. Such a review, however, will not reveal all existing or potential 
problems nor will it permit a buyer to become sufficiently familiar with the 
properties to fully assess the deficiencies and capabilities of such 
properties. Inspections may not always be performed on every well, and 
structural and environmental problems are not necessarily observable even 
when an inspection is undertaken. Even when problems are identified, the 
seller may be unwilling or unable to provide effective contractual protection 
against all or part of such problems. There can be no assurance that the 
Company will be able to identify attractive acquisition opportunities, obtain 
financing for acquisitions on satisfactory terms or successfully acquire 
identified targets. Furthermore, there can be no assurance that competition 
for acquisition opportunities in these industries will not escalate, thereby 
increasing the cost to the Company of making further acquisitions or causing 
the Company to refrain from making further acquisitions. In addition, there 
can be no assurance that any acquisition of property interests by the Company 
will be successful and, if unsuccessful, that such failure will not have a 
material adverse effect on the Company's future results of operations and 
financial condition. The Company's current inability to borrow to fund its 
capital expenditures will, for so long as it continues, adverse affect its 
ability to fund its acquisition strategy.

                                      25
<PAGE>

OPERATIONAL HAZARDS AND UNINSURED RISKS

         Oil and natural gas drilling activities are subject to numerous 
risks, many of which are beyond the Company's control, including the risk 
that no commercially productive oil or natural gas reservoirs will be 
encountered. The cost of drilling, completing and operating wells is often 
uncertain, and drilling operations may be curtailed, delayed or canceled as a 
result of a variety of factors, including unexpected drilling conditions, 
pressure irregularities information, equipment failures or accidents, adverse 
weather conditions, title problems and shortages or delays in the delivery of 
equipment. The Company's future drilling activities may not be successful 
and, if unsuccessful, such failure will have an adverse effect on future 
results of operations and financial condition.

         In addition, oil and natural gas operations involve hazards such as 
fire, explosion, blowout, pipe failure, casing collapse, unusual or 
unexpected formation pressures and environmental hazards such as oil spills, 
gas leaks, ruptures and discharges of toxic gases, the occurrence of any one 
of which could result in substantial losses to the Company due to injury or 
loss of life, severe damage to or destruction of property, natural resources 
and equipment, pollution or other environmental damage, cleanup 
responsibilities, regulatory investigation and penalties and suspension of 
operations. Although the Company maintains insurance against certain risks 
that it believes are customarily insured against by companies in the industry 
of comparable size and scope of operations, such insurance does not cover all 
of the risks and hazards involved in oil and natural gas exploration, 
drilling and production because insurance is unavailable at economic rates, 
there are limitations in the Company's insurance policies or for other 
reasons. Even if coverage does exist, it may not be sufficient to pay the 
full amount of liabilities incurred, and there can be no assurance that such 
insurance will continue to be available on terms acceptable to the Company. 
Any uninsured loss could have a material adverse effect on the Company's 
financial condition and results of operations.

COMPETITION IN THE OIL AND NATURAL GAS INDUSTRY

         The Company encounters competition from other oil and natural gas 
companies in all areas of its operations, including the acquisition of 
exploratory prospects and proven properties. Properties within the Lobo Trend 
are characterized by large tracts (typically 5,000 to 50,000 acres) that have 
been owned by the same families for generations. Securing leases or necessary 
permits and approvals for 3-D seismic shoots depends heavily on developing 
and maintaining favorable relationships with the surface owners. The 
Company's competitors, particularly in the Lobo Trend, include major 
integrated oil and natural gas companies and independent oil and natural gas 
companies, individuals and drilling and income programs. Most of its 
competitors are large, well-established companies with substantially larger 
operating staffs and significantly greater capital resources than those of 
the Company and which, in many instances, have been engaged in the oil and 
natural gas business for a much longer time than the Company. Such companies 
may be able to pay more for exploratory prospects and productive oil and 
natural gas properties and may be able to define, evaluate, bid for and 
purchase a greater number of properties and prospects than could the Company, 
given its limited financial and human resources. There can be no assurance 
that the Company will be able to secure the necessary financing or industry 
partners or evaluate and select suitable properties and consummate 
transactions in this highly competitive environment. See "Item 1. Business--
Competition."

PROPERTY IMPAIRMENT CHARGES

         Effective January 1, 1996, the Company adopted Statement of 
Financial Accounting Standards ("SFAS") No. 121, "Accounting for the 
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," 
which requires that long-lived assets held and used by an entity be reviewed 
for impairment whenever events or changes indicate that the net book value of 
an asset may not be recoverable. The net book value of an asset is reduced to 
fair value if the sum of expected undiscounted future net cash flows from the 
use of the asset is less than the net book value of the asset. Under SFAS No. 
121 the Company evaluates impairment of oil and natural gas properties on a 
field basis. Applying SFAS No. 121, the Company recognized non-cash property 
impairment charges of $5.4 million, $238,000 and $156,000 as of December 31, 
1998, 1997 and 1996, respectively. See "Item 7. Management's Discussion and 
Analysis of Financial Condition and Results of Operations--Results of 
Operations." Significant declines in oil or natural gas prices or downward 
revisions of reserve estimates could adversely impact the Company's estimates 
of future net revenues from its proved reserves and consequently could result 
in future non-cash impairment charges against the Company's results of 
operations.

DEPENDENCE OF KEY PERSONNEL

         The Company is dependent upon the efforts and skills of key 
executives of the Company, including Glenn D. Hart, Chairman of the Board and 
Chief Executive Officer, Michael G. Farmar, President and Chief Operating 
Officer,

                                      26
<PAGE>

and Jerry F. Holditch, Vice President-Exploration. The loss of any of these 
officers or other key personnel could have a material adverse effect on the 
Company. Further, as the Company grows its asset base and scope of operations 
as a result of the Transactions and other future acquisitions, its future 
profitability will depend upon the Company's ability to attract and retain 
additional qualified personnel.

CONTROL BY CERTAIN SHAREHOLDERS

         The Company is a wholly-owned subsidiary of MHI, which in turn is 
principally owned by the management of the Company and MHI. Four of the 
Company's directors, three of whom are also executive officers of the 
Company, beneficially owned 701,550 shares of common stock of MHI (the 
"Common Stock") representing, in the aggregate, approximately 91% of the 
outstanding Common Stock. Such owners, should they act together, would have 
sufficient voting power to (i) elect the entire Boards of Directors of the 
Company and MHI, (ii) exercise control over the business, policies and 
affairs of the Company and MHI and (iii) in general, determine the outcome of 
any corporate transaction or other matters submitted to the stockholders for 
approval such as (a) any amendment to the Company's Articles of 
Incorporation, (b) the authorization of additional shares of capital stock 
and (c) any merger, consolidation or sale of all or substantially all of the 
assets of the Company which could prevent or cause a change of control of the 
Company.

REGULATORY AND ENVIRONMENTAL RISKS

         Oil and natural gas operations are subject to various federal, state 
and local governmental regulations which may be changed from time to time in 
response to economic or political conditions. From time to time, regulatory 
agencies have imposed price controls and limitations on production in order 
to conserve supplies of oil and natural gas. In addition, the production, 
handling, storage, transportation and disposal of oil and natural gas, 
byproducts thereof and other substances and materials produced or used in 
connection with oil and natural gas operations are subject to regulation 
under federal, state and local laws and regulations. 

         The Company's operations currently are located primarily in Texas. 
Thus, the Company's business is subject to environmental regulation on the 
state level primarily by the Railroad Commission of Texas and the Texas 
Natural Resource Conservation Commission. The Railroad Commission of Texas 
regulations may require on the Company to obtain permits and drilling bonds 
for the drilling of wells. Additionally, the Railroad Commission of Texas 
regulates the spacing of wells, plugging and abandonment of such wells and 
the remediation of contamination caused by most types of exploration and 
production wastes. The Railroad Commission requirements for remediation of 
contamination are, for the most part, administered on a case-by-case basis. 
The Company expects that such regulations will be formalized in the future 
and will in all likelihood become more stringent.

         Currently, federal regulations provide that drilling fluids, 
produced waters and other wastes associated with the exploration, development 
or production of oil and natural gas are exempt from regulation as "hazardous 
waste." To the extent that the Company's operations produce wastes that do 
not fall within this exemption, the storage, handling and disposal of those 
wastes are regulated on the state level by the Texas Natural Resource 
Conservation Commission. From time to time, legislation has been proposed to 
eliminate or modify this exemption. Should the exemption be modified or 
eliminated, wastes associated with oil and natural gas exploration and 
production would be subject to more stringent regulation. On the federal 
level, the Company's operations may be subject to various federal statutes, 
including the Natural Gas Act, the Comprehensive Environmental Response, 
Compensation the Liability Act, the Solid Waste Disposal Act, as amended by 
the Resource Conservation and Recovery Act, the Clean Air Act, the Federal 
Water Pollution Control Act and the Oil Pollution Act, as well as by 
regulations promulgated pursuant to these actions.

         These regulations subject the Company to increased operating costs 
and potential liability associated with the use and disposal of hazardous 
materials. Although these laws and regulations have not had a material 
adverse effect on the Company's financial condition or results of operations, 
there can be no assurance that the Company will not be required to make 
material expenditures in the future. Moreover, the Company anticipates that 
such laws and regulations will become increasingly stringent in the future, 
which could lead to material costs for environmental compliance and 
remediation by the Company.

         Any failure by the Company to obtain required permits for, control 
the use of, or adequately restrict the discharge of hazardous substances 
under present or future regulations could subject the Company to substantial 

                                      27
<PAGE>

liability or could cause its operations to be suspended. Such liability or 
suspension of operations could have a material adverse effect on the 
Company's business, financial condition and results of operations.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

         In June 1998, the FASB issued SFAS No. 133, ACCOUNTING FOR 
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES, which is effective for fiscal 
years beginning after June 15, 1999. SFAS No. 133 establishes accounting and 
reporting standards for derivative instruments, including certain derivative 
instruments embedded in other contracts, and for hedging activities. It also 
requires that an entity recognize all derivatives as either assets or 
liabilities in the statement of financial position and measure those items at 
fair value. If certain conditions are met, a derivative may be specifically 
designated as (a) a hedge of the exposure to changes in the fair value of a 
recognized asset or liability or an unrecognized firm commitment, (b) a hedge 
of the exposure to variable cash flows of a forecasted transaction, or (c) a 
hedge of the foreign currency exposure of a net investment in a foreign 
operation, an unrecognized firm commitment, an available-for-sale security, 
or a foreign-currency-denominated forecasted transaction. As discussed in 
Note 5 to the Financial Statements, the Company has historically hedged a 
portion of its future gas production using gas swap contracts. These 
contracts are a hedge of the Company's exposure to the variability of future 
cash flows due to potential decreases in gas prices. For a derivative 
designated as hedging the exposure to variable cash flows of a forecasted 
transaction (referred to as a cash flow hedge), the effective portion of the 
derivative gain or loss is initially reported as a component of other 
comprehensive income (outside earnings) and subsequently reclassified into 
earnings when the forecasted transaction affects earnings. The ineffective 
portion of the gain or loss is reported in earnings immediately. The extent 
of the impact of adopting SFAS No. 133 on the Company's consolidated 
financial position, results of operations, or cash flows will be a function 
of the open derivative contracts at the date of adoption. As of December 31, 
1998, the Company can not estimate the impact of SFAS 133 on the consolidated 
financial position, results of operations or cash flows.

                                      28
<PAGE>

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

HEDGING ACTIVITIES

         From time to time, the Company has utilized hedging transactions 
including swaps, put options and costless collars, with respect to a portion 
of its oil and natural gas production to achieve a more predictable cash 
flow, as well as to reduce exposure to price fluctuations. While the use of 
these hedging arrangements limits the downside risk of adverse price 
movements, they may also limit future revenues from favorable price 
movements. The use of hedging transactions also involves risk that the 
counterparties will be unable to meet the financial terms of such 
transactions. All of the Company's hedging transactions to date were carried 
out in the over-the-counter market and the obligations of the counterparties 
have been guaranteed by entities with at lest an investment grade rating or 
secured by letters of credit. The Company accounts for these transactions as 
hedging activities and, accordingly, gains or losses are included in oil and 
gas revenues when the hedged production is delivered. Neither the hedging 
contracts nor the unrealized gains or losses on these contracts are 
recognized in the financial statements. In addition, if the Company's 
reserves are not produced at the rates estimated by the Company due to 
inaccuracies in the reserve estimation process, operational difficulties or 
regulatory limitations, or otherwise, the Company would be required to 
satisfy its obligations under potentially unfavorable terms. The Company may 
be at a risk for basis differential, which is the difference in the quoted 
financial price for contract settlement and the actual physical point of 
delivery price. Substantial variations between the assumptions and estimates 
used by the Company in its hedging activities and actual results experienced 
could materially adversely affect the Company's financial condition and its 
ability to manage risk associated with fluctuations in oil and natural gas 
prices.

         The annual average oil and natural gas prices received by the 
Company have fluctuated significantly over the past three years. 
Approximately 54%, 72% and 48% of the Company's production was hedged during 
the years ended December 31, 1996, 1997 and 1998, respectively. The Company's 
weighted average natural gas price received per Mcf (including the effects of 
hedging transactions) was $2.15, $2.33 and $2.07 during the years ended 
December 31, 1996, 1997 and 1998, respectively. Hedging transactions resulted 
in a ($0.24), ($0.32) and $0.01 (reduction) increase in the Company's 
weighted average natural gas price received per Mcf in 1996, 1997 and 1998, 
respectively. The fair value of these hedging contracts was $(1.1 million), 
$(1.1 million) and $2.1 million as of December 31, 1996, 1997, and 1998, 
respectively.

         As of December 31, 1998, the Company had entered into commodity 
price hedging contracts with respect to its gas production for 1999 and 2000 
as follows:

<TABLE>
<CAPTION>
                                                              PRICE PER MMbtu
                                             ------------------------------------------------
                                                         COLLAR
                               VOLUME IN     -------------------------------
         PERIOD                  MMbtu           FLOOR            CEILING        STRIKE PRICE
-------------------------      ---------     -------------     -------------     ------------
<S>                            <C>           <C>               <C>               <C>
Jan 1999 - Dec 1999
Put option                       600,000                                            $2.25
Costless collar                1,800,000         $2.25            $2.99
Costless collar                1,800,000         $2.00            $2.22
Costless collar                2,400,000         $2.15            $2.38
Costless collar                1,800,000         $1.98            $2.22
Costless collar                1,200,000         $2.15            $2.36

Jan 2000 - April 2000
Costless collar                  600,000         $2.00            $2.22
Costless collar                1,200,000         $2.15            $2.38
Costless collar                  600,000         $1.98            $2.22
Costless collar                  600,000         $2.15            $2.36
</TABLE>

         These hedging transactions are settled based on settlement prices 
relative to a Houston Ship Channel Index. With respect to any particular 
costless collar transaction, the counterparty is required to make a payment 
to the Company if the settlement price for any settlement period is below the 
floor price for such transaction, and the Company is required to make payment 
to the counterparty if the settlement price for any settlement period is 
above the ceiling price for such transaction. For put options, the 
counterparty is required to make payment to the Company if the settlement 
price for any settlement period is below the strike price for such 
transaction. The Company is not required to make any payment in connection 
with the settlement of put options. The premium paid by the Company for the 
put option was approximately $229,500. As of December 31, 1998, approximately 
$76,500 remains unamortized.

The borrowings under the Credit Facility and the value of the $135 million 
Series B Notes are subject to market fluctuations as influenced by certain 
economic factors and events. The interest rate for borrowings under the 
Credit Facility are determined at one of two floating interest rates (ABR 
rate or Eurodollar rate) plus 0.5% to 2.25% at the election of the Company. 
Thus, the fair value of the Credit Facility approximates its market value. 
The fair value of the $135 million Series B Notes was approximately $120 
million at December 31, 1998 and the effective interest rate was 12.04%.


                                      29

<PAGE>

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
                                                                            PAGE
                                                                            ----
<S>                                                                         <C>
Report of Independent Accountants.......................................... 31
Consolidated Balance Sheets................................................ 32
Consolidated Statement of Operations....................................... 33
Consolidated Statement of Stockholder's Deficit............................ 34
Consolidated Statement of Cash Flows....................................... 35
Notes to Consolidated Financial Statements................................. 36
</TABLE>




                                      30

<PAGE>

REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Stockholders of Michael Petroleum Corporation:

In our opinion, the accompanying consolidated balance sheets and the related 
consolidated statements of operations, stockholder's deficit, and cash flows 
present fairly, in all material respects, the financial position of Michael 
Petroleum Corporation at December 31, 1998 and 1997, and the results of its 
operations and its cash flows for each of the three years in the period ended 
December 31, 1998, in conformity with generally accepted accounting 
principles. 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 of these 
statements in accordance with generally accepted auditing standards which 
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, assessing the accounting 
principles used and significant estimates made by management, and evaluating 
the overall financial statement presentation. We believe that our audits 
provide a reasonable basis for the opinion expressed above.
                                       


                                       PricewaterhouseCoopers LLP


Houston, Texas
March 31, 1999



                                      31
<PAGE>

MICHAEL PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands of dollars, except share data)

<TABLE>
<CAPTION>
                                                                           DECEMBER 31,
                                                                     ----------------------
                                                                       1997          1998
                                                                     -------       --------
<S>                                                                  <C>           <C>
                                          ASSETS
Current assets:
  Cash and cash equivalents                                          $   782       $    430
  Receivables:
    Accrued oil and gas sales                                          3,991          5,362
    Joint interest and other                                             481          1,004
  Note receivable                                                        --           1,500
  Prepaid expenses and other                                               1            655
                                                                     -------       --------
      Total current assets                                             5,255          8,951

Oil and gas properties (successful efforts method), at cost           34,977        155,867
Less:  accumulated depletion, depreciation and amortization           (6,966)       (24,989)
                                                                     -------       --------

                                                                      28,011        130,878

Deferred income taxes                                                                 1,876
Other assets                                                             351          5,577
                                                                     -------       --------

      Total assets                                                   $33,617       $147,282
                                                                     =======       ========

                         LIABILITIES AND STOCKHOLDER'S DEFICIT

Current liabilities:
  Accounts payable:
    Trade                                                            $ 3,746       $  7,202
    Revenue distribution                                               1,756          1,723
  Accrued interest                                                       263          4,076
  Accrued liabilities                                                     35            554
  Current portion of long-term debt                                    8,056             41
                                                                     -------       --------

      Total current liabilities                                       13,856         13,596

Long-term debt                                                        19,885        144,842
Deferred income taxes                                                  1,791            --
                                                                     -------       --------

      Total liabilities                                               35,532        158,438

Commitments and contingencies (Note 10)

Stockholder's deficit:
  Preferred stock ($.10 par value, 50,000,000 shares authorized,
    no shares issued)
  Common stock ($.10 par value, 100,000,000 shares authorized,
    10,000 shares issued and outstanding)                                  1              1
  Additional paid-in capital                                             610            610
  Accumulated deficit                                                 (2,526)       (11,767)
                                                                     -------       --------

      Total stockholder's deficit                                     (1,915)       (11,156)
                                                                     -------       --------

      Total liabilities and stockholder's deficit                    $33,617       $147,282
                                                                     =======       ========
</TABLE>

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.



                                      32

<PAGE>

MICHAEL PETROLEUM CORPORATION
CONSOLIDATED STATEMENT OF OPERATIONS
(In thousands of dollars)

<TABLE>
<CAPTION>
                                                                       YEAR ENDED DECEMBER 31,
                                                                ----------------------------------
                                                                  1996         1997         1998
                                                                -------      -------      --------
<S>                                                             <C>          <C>          <C>
Revenues:
  Oil and natural gas sales                                     $ 3,594      $ 9,139      $ 22,668
  Gain on sale of oil and natural gas properties                    182          -              50
                                                                -------      -------      --------

                                                                  3,776        9,139        22,718
                                                                -------      -------      --------

Operating expenses: 
  Production costs                                                1,931        1,870         4,118
  Depletion, depreciation and amortization                        1,024        3,651        12,620
  Impairment of oil and natural gas properties                      156          238         5,424
  Exploration                                                        46          333            85
  General and administrative                                        424          980         1,802
                                                                -------      -------      --------

                                                                  3,581        7,072        24,049
                                                                -------      -------      --------

Operating income (loss)                                             195        2,067        (1,331)
                                                                -------      -------      --------

Other income (expense):
  Interest income and other                                          30           46           235
  Interest expense and other                                       (924)      (2,109)      (12,281)
                                                                -------      -------      --------

                                                                   (894)      (2,063)      (12,046)

(Loss) income before income taxes and extraordinary item           (699)           4       (13,377)
Provision (benefit) for income taxes                              1,780           11        (4,667)
                                                                -------      -------      --------
Loss before extraordinary item                                   (2,479)          (7)       (8,710)

Extraordinary item - extinguishment of T.E.P. Financing, 
  net of tax of $285                                                -            -           (531)
                                                                -------      -------      --------

Net loss                                                        $(2,479)     $    (7)     $ (9,241)
                                                                =======      =======      ========
</TABLE>

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.



                                      33
<PAGE>

MICHAEL PETROLEUM CORPORATION 
CONSOLIDATED STATEMENT OF STOCKHOLDER'S DEFICIT
For the years ended December 31, 1996, 1997 and 1998 
(In thousands of dollars, except per share data)

<TABLE>
<CAPTION>
                                                    COMMON STOCK
                                                  -----------------     ADDITIONAL
                                                                          PAID-IN      ACCUMULATED
                                                  SHARES     AMOUNT      CAPITAL         DEFICIT         TOTAL
                                                  ------     ------     ----------     -----------     --------
<S>                                               <C>        <C>        <C>            <C>             <C>
Balance, December 31, 1995                            10       $1          $455         $    (31)      $    425

Dividend to MHI                                                                               (9)            (9)

Issuance of warrants in conjunction with T.E.P. 
  Financing                                                                 155                             155

Net loss                                                                                  (2,479)        (2,479)
                                                   ----       ---          ----         --------       --------
Balance, December 31, 1996                           10        $1           610           (2,519)        (1,908)

Net loss                                                                                      (7)            (7)
                                                   ----       ---          ----         --------       --------
Balance, December 31, 1997                           10        $1           610           (2,526)        (1,915)

Net loss                                                                                  (9,241)        (9,241)
                                                   ----       ---          ----         --------       --------
Balance December 31, 1998                            10        $1          $610         $(11,767)      $(11,156)
                                                   ====       ===          ====         ========       ========
</TABLE>


THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.



                                      34

<PAGE>

MICHAEL PETROLEUM CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(In thousands of dollars)

<TABLE>
<CAPTION>
                                                                            YEAR ENDED DECEMBER 31,
                                                                     ------------------------------------
                                                                       1996         1997           1998
                                                                     --------     --------      ---------
<S>                                                                  <C>          <C>           <C>
Cash flows from operating activities:
  Net loss                                                           $ (2,479)    $     (7)     $  (9,241)
  Adjustments to reconcile net loss to net cash provided by                                               
    operating activities:                                                                                 
      Depletion, depreciation and amortization                          1,024        3,651         12,620
      Impairment of oil and natural gas properties                        156          238          5,424
      Deferred income taxes                                             1,780           11         (4,952)
      Extraordinary item - extinguishment of T.E.P. 
        Financing, net of taxes                                           --           --             470
      Gain on sale of oil and gas properties                             (182)         --             (50)
      Abandonment of oil and gas properties                               --           249             35
      Amortization of debt and bond issuance costs                        --           --             619
      Amortization of deferred loss on early termination of 
        commodity swap agreement                                          --           --             712
      Amortization of discount on debt                                     43          131            205
      Changes in assets and liabilities: 
        Accounts receivable - accrued oil and gas sales                (1,189)      (2,333)        (1,370)
        Accounts receivable - joint interest and other                   (682)         562           (514)
        Prepaid expenses and other                                          2           72         (1,236)
        Accounts payable - trade                                        1,350          710         (1,769)
        Accounts payable - revenue distribution                           846          296            (32)
        Accrued interest                                                   73         (121)         3,813
        Accrued liabilities                                               106            7            518
                                                                     --------     --------      ---------

          Net cash provided by operating activities                       848        3,466          5,252
                                                                     --------     --------      ---------

Cash flows from investing activities:
  Additions to oil and gas properties                                 (14,981)     (14,963)      (114,978)
  Proceeds from sale of oil and gas properties                            228          --             150
  Issuance of note receivable                                             --           --          (1,500)
                                                                     --------     --------      ---------

          Net cash used in investing activities                       (14,753)     (14,963)      (116,328)
                                                                     --------     --------      ---------

Cash flows from financing activities:
  Proceeds from long-term debt                                         17,329       14,238        145,603
  Payments on long-term debt                                           (2,130)      (3,114)       (29,314)
  Dividend to MHI                                                          (9)         --             --
  Additions to deferred loan costs                                       (440)         (26)        (5,565)
                                                                     --------     --------      ---------

          Net cash provided by financing activities                    14,750       11,098        110,724

Net increase (decrease) in cash and cash equivalents                      845         (399)          (352)

Cash and cash equivalents, beginning of period                            336        1,181            782
                                                                     --------     --------      ---------

Cash and cash equivalents, end of period                             $  1,181     $    782      $     430
                                                                     ========     ========      =========
</TABLE>

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.


                                      35

<PAGE>

MICHAEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.   NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

     NATURE OF OPERATIONS AND BASIS OF PRESENTATION

     Michael Petroleum Corporation and Subsidiaries (the "Company" or "MPC") is
     engaged in the acquisition, exploration and development of oil and natural
     gas properties principally located in the Lobo Trend of South Texas. The
     Company was incorporated in June 1982. The Company, which was owned by the
     stockholders of Michael Holdings, Inc. ("MHI"), became a wholly-owned
     subsidiary of MHI on July 1, 1996 in a transaction accounted for at
     historical cost as a reorganization of entities under common control.

     On March 25, 1998, the Company was merged with and into Michael Gas
     Production Company ("MGPC"), which was also a wholly-owned subsidiary of
     MHI. Following the merger, MGPC changed its name to MPC. This transaction
     was accounted for at historical cost as a reorganization of entities under
     common control. The consolidated financial statements reflect the financial
     position, results of operations and cash flows of the combined companies
     for all periods presented as if the merger had occurred on December 31,
     1995. The consolidated financial statements contain the accounts of the
     Company after elimination of all significant intercompany balances and
     transactions.

     As an independent oil and gas producer, the Company's revenue, 
     profitability and future rate of growth are substantially dependent upon 
     prevailing prices for natural gas, oil and condensate, which are 
     dependent upon numerous factors beyond the Company's control, such as 
     economic, political and regulatory developments and competition from 
     other sources of energy. The energy markets have historically been very 
     volatile, as evidenced by the recent volatility of oil and gas prices, 
     and there can be no assurance that oil and gas prices will not be 
     subject to wide fluctuations in the future. A substantial or extended 
     decline in oil and gas prices could have a material adverse effect on 
     the Company's consolidated financial position, results of operations, 
     cash flows, quantities of oil and gas reserves that may be economically 
     produced and access to capital. Natural gas approximates 87% and 97% of 
     the Company's proved reserves at December 31, 1998 and 1997, 
     respectively.

     CASH AND CASH EQUIVALENTS

     Cash equivalents consist of short-term highly liquid investments that have
     an original maturity of three months or less. The Company maintains its
     cash with two financial institutions. The Company periodically assesses the
     financial condition of the institutions and believes that any possible
     credit risk is minimal.

     OIL AND GAS PROPERTIES

     The Company follows the successful efforts method of accounting for its 
     oil and gas properties. Under this method of accounting, all property
     acquisition costs and costs of exploratory and development wells are
     capitalized when incurred, pending determination of whether the well has
     found proved reserves. If an exploratory well has not found proved
     reserves, the costs of drilling the well are charged to expense. The costs
     of development wells are capitalized whether productive or nonproductive.

     Geological and geophysical costs on exploratory prospects and the costs of
     carrying and retaining unproved properties are expensed as incurred. An
     impairment allowance is provided to the extent that capitalized costs of
     unproved properties, on a property-by-property basis, are considered to be
     not realizable.

     Depletion, depreciation and amortization ("DD&A") of development costs and
     acquisition costs of proved oil and gas properties is provided using the
     units-of-production method based on proved developed reserves and proved
     reserves, respectively. The computation of DD&A takes into consideration
     restoration, dismantlement and abandonment costs and the anticipated
     proceeds from equipment salvage. The estimated restoration, dismantlement
     and abandonment costs are expected to be offset by the estimated residual
     value of lease and well equipment.

     Gains and losses are recognized on sales of entire interests in proved and
     unproved properties. Sales of partial interests are generally treated as
     recoveries of costs.
                                       


                                      36

<PAGE>

     NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


     IMPAIRMENT OF OIL AND GAS PROPERTIES

     The net book value of an asset is reduced to fair value if the sum of
     expected undiscounted future net cash flows from the use of the asset is
     less than the net book value of the asset. The Company evaluates impairment
     of its oil and gas properties on a field basis. The Company makes a
     determination of any market changes or performs a periodic review of all 
     fields each year.

     NATURAL GAS BALANCING

     The Company incurs natural gas production volume imbalances in the ordinary
     course of business on jointly owned properties. The Company follows the
     sales method to account for such imbalances. Under this method, revenue is
     recorded based on the Company's net revenue interest in production taken
     for delivery. The Company records a liability if its sales of gas volumes
     in excess of its entitlements from a jointly owned reservoir exceed its
     interest in the remaining estimated natural gas reserves of such reservoir.
     Volumetric production is monitored to minimize imbalances, and such
     imbalances were not significant at December 31, 1997 and 1998.

     OTHER ASSETS

     Other assets include loan origination costs which are amortized on a
     straight-line basis over the term of the related obligation.

     INCOME TAXES

     Through June 30, 1996, the Company was taxed under the provisions of 
     "Subchapter S" of the Internal Revenue Code, which provides that the 
     individual shareholders are liable for federal income taxes on the 
     Company's taxable income. Accordingly, no provision for federal income 
     taxes is reflected in the consolidated statement of operations for 
     periods ending prior to June 30, 1996. Effective July 1, 1996, the 
     Company began filing a consolidated federal income tax return with MHI.

     Deferred income taxes are provided to reflect the tax consequences in
     future years of differences between the financial statement and tax bases
     of assets and liabilities. Tax credits are accounted for under the
     flow-through method, which reduces the provision for income taxes in the
     year the tax credits are earned. A valuation allowance is established to
     reduce deferred tax assets if it is more likely than not that the related
     tax benefits will not be realized. The Company calculates current and
     deferred taxes on an individual company basis.

     STOCK-BASED COMPENSATION

     Statement of Financial Accounting Standards No. 123, ACCOUNTING FOR
     STOCK-BASED COMPENSATION, encourages, but does not require companies to
     record compensation cost for stock-based employee compensation plans at
     fair value. The Company has chosen to continue to apply Accounting
     Principles Board Opinion No. 25, ACCOUNTING FOR STOCK ISSUED TO EMPLOYEES,
     and related interpretations to account for stock-based compensation.
     Accordingly, compensation cost for stock options is measured as the excess,
     if any, of the quoted market price of the Company's stock at the date of
     the grant over the amount an employee must pay to acquire the stock.

     PRICE RISK MANAGEMENT ACTIVITIES

     The Company periodically uses swaps, put options and costless collars to
     hedge or otherwise reduce the impact of natural gas price fluctuations.
     Gains and losses resulting from changes in the market value of the
     financial instruments utilized as hedges are deferred and recognized in 
     the statement of operations, together with the gain or loss on the hedged
     transaction, as the physical production is sold under the relevant
     contracts. Cash flows resulting from the Company's risk management
     activities are classified in the accompanying statement of cash flows 
     in the same category as the item being hedged.

     These instruments are measured for effectiveness on an enterprise basis
     both at the inception of the contract and on an ongoing basis. If these
     instruments are terminated prior to maturity, resulting gains or losses
     continue to be deferred until the hedged item is recognized in income.

     In connection with these hedging transactions, the Company may be exposed
     to nonperformance by other parties to such agreements, thereby subjecting
     the Company to current natural gas prices. However, the Company only enters
     into hedging contracts with large financial institutions and does not
     anticipate nonperformance.
                                       


                                      37

<PAGE>

     NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


     CONCENTRATION OF CREDIT RISK

     Substantially all of the Company's receivables are within the oil and gas
     industry, primarily from purchasers of oil and gas and joint venture
     participants. Collectibility is dependent upon the general economic
     conditions of the purchasers and the oil and gas industry. The receivables
     are not collateralized and to date, the Company has had minimal bad debts.

     FAIR VALUE OF FINANCIAL INSTRUMENTS

     The carrying amounts reported in the balance sheet for cash and cash
     equivalents, receivables, and accounts payable approximate their fair
     value. The fair value of the Company's long-term debt and derivative
     financial instruments are estimated using current market quotes.

     USE OF ESTIMATES

     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. The Company's most significant estimates 
     relate to the assessment of impairment of proved and unproved oil and 
     gas properties, depreciation, depletion, and amortization expense, 
     proved oil and gas reserves and utilization of deferred tax assets. 
     Actual results could differ from these estimates.

2.   OIL AND GAS PROPERTY TRANSACTIONS:

     In August 1996, the Company acquired certain oil and natural gas 
     properties in Webb County and Zapata County, Texas (the "1996 
     Acquisition") for approximately $11.8 million. As a result, unaudited 
     pro forma revenues and income from continuing operations for the year 
     ended December 31, 1996 were $8,730,000 (unaudited) and $2,497,000 
     (unaudited), respectively.

     In March 1998, the Company completed the acquisition of interests in 
     certain oil and natural gas properties in Webb County, Hildago County 
     and Zapata County, Texas, and certain related seismic data from Enron 
     Oil & Gas Company (the "Enron Acquisition") for $45.8 million.

     In April 1998, the Company completed the acquisition of certain oil and
     natural gas leases in Webb County, Texas, from Conoco Inc. (the "Conoco
     Acquisition") for $22.5 million.

     In April 1998, the Company entered into a lease with Mobil effective as of
     January 1, 1998 in the Lobo Trend (the "Lobo Lease"). Consideration for the
     Lobo Lease is in the form of future deliveries of 4 Bcf of gas, which
     commenced May 1, 1998 and terminated December 31, 1998. On April 23, 1998,
     the Company entered into a contract to secure delivery of this volume of
     gas for consideration of $9.98 million.

     The following pro forma data presents the results of the Company for the
     years ended December 31, 1997 and 1998, as if the acquisitions of the Lobo
     Lease, the Conoco Acquisition and the Enron Acquisition had occurred on
     January 1, 1997. The pro forma results of operations are presented for
     comparative purposes only and are not necessarily indicative of results
     which would have been obtained had the acquisitions been consummated as
     presented. The following data reflect pro forma adjustments for oil and
     natural gas revenues, production costs, depreciation, and depletion related
     to the properties acquired, interest on borrowed funds, and related income
     tax effects (in thousands):

<TABLE>
<CAPTION>
                                                         YEAR ENDED DECEMBER 31,
                                                        -------------------------
                                                         1997              1998
                                                        -------           -------
                                                               (UNAUDITED)
          <S>                                           <C>               <C>
          Pro forma:
            Revenues                                    $31,209           $26,563
            Loss from continuing operations              (1,465)           (9,375)
</TABLE>
                                       


                                      38

<PAGE>

     NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


3.   LONG-TERM DEBT:

     Long-term debt consisted of the following (in thousands):

<TABLE>
<CAPTION>
                                                                                                              DECEMBER 31,
                                                                                                      ---------------------------
                                                                                                        1997               1998
                                                                                                      --------           --------
          <S>                                                                                         <C>                <C>
          11 1/2% Senior Notes due 2005                                                                      -           $135,000
          Credit Facility                                                                                    -             12,000
          Notes payable under the comprehensive credit agreement                                      $ 28,266                  -
          Installment notes to financial institutions, payable monthly, interest at rates
            ranging from 3.9% to 11.26%, due April 1996 to September 2001, collateralized                  
            by vehicles and office equipment                                                               139                 65
          Note payable to an individual, payable monthly, interest at 8%, due February 2000,                
            unsecured                                                                                       17                  9
                                                                                                      --------           --------

                                                                                                        28,422            147,074
                                                                                                      --------           --------

          Unamortized original issue discount on Senior Notes                                                              (2,191)

          Unamortized discount on note payable under comprehensive credit agreement                       (481)                 -
                                                                                                      --------           --------

          Total long-term debt                                                                          27,941            144,883
                                                                                                      --------           --------

          Less:  current portion                                                                        (8,056)               (41)
                                                                                                      --------           --------

              Long-term debt                                                                           $19,885           $144,842
                                                                                                      ========           ========
</TABLE>

     Estimated annual principal payments at December 31, 1998 are as follows 
(in thousands):

<TABLE>
                         <S>                                                                          <C>
                         1999                                                                         $     41
                         2000                                                                               25
                         2001                                                                                8
                         2002                                                                           12,000
                         2003                                                                                -
                         Thereafter                                                                    135,000
                                                                                                      --------
                                                                                                      $147,074
                                                                                                      ========
</TABLE>


     SENIOR NOTES

     On April 2, 1998, the Company issued $135 million of Senior Notes at a 
     discount of 1.751%. The Senior Notes mature in April 2005 and bear 
     interest at a rate of approximately 11.5% per annum, payable 
     semi-annually in April and October of each year, commencing October 
     1998. The effective interest rate under the Senior Notes for the year 
     ended December 31, 1998 was 12.04%. Bond discount costs are amortized on 
     the interest method over the term of the Senior Notes. The Senior Notes 
     are redeemable at the option of the Company, in whole or in part, at any 
     time after April 2003, at specified redemption prices plus accrued and 
     unpaid interest and liquidated damages, as defined. In the event of 
     certain asset dispositions, the Company is required under certain 
     circumstances to use the excess proceeds from such a disposition to 
     offer to repurchase the Senior Notes (and other Senior Indebtedness for 
     which an offer to repurchase is required to be concurrently made). The 
     Company is required to comply with certain covenants, which limit, among 
     other things, the ability of the Company to incur additional 
     indebtedness, pay dividends, repurchase equity interests, sell assets or 
     enter into mergers and consolidations. The fair value of the Senior 
     Notes was $120 million at December 31, 1998.
                                       


                                      39

<PAGE>

     NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


     T.E.P. FINANCING

     On August 13, 1996, the Company entered into a comprehensive credit
     agreement (the "T.E.P. Financing") with a limited partnership. Under the
     T.E.P. Financing, total available credit amounted to approximately $42.2
     million, of which $16.3 million was available for oil and gas property
     acquisitions and $25.9 million for development costs.

     The Company utilized loan proceeds of approximately $14.9 million to 
     acquire proved oil and gas properties located in South Texas the 1996 
     Acquisition. Through 1997, loan proceeds of approximately $11.8 million 
     had been used to develop those properties. In conjunction with entering 
     into the T.E.P. Financing, the Company conveyed to an affiliate of the 
     lender a net profits interest in all of the Company's oil and gas 
     properties, including the acquired properties ("Net Profits Interest"). 
     The Net Profits Interest granted the affiliate 30% of the net profits, 
     as defined, beginning the earlier of August 12, 2001, or the date of 
     repayment of all amounts due and owing pursuant to the T.E.P. Financing. 
     The Net Profits Interest decreased to 15% of the net profits, as 
     defined, after payment of $10 million. As part of the T.E.P. Financing, 
     the Company also granted to the lender a warrant to purchase up to five 
     percent of MHI's common stock at an exercise price of $8 per share until 
     August 12, 2001. The value assigned to the Net Profits Interest and 
     warrant was recorded as a discount to the loan proceeds.

     Under the terms of the T.E.P. Financing, principal was payable as a 
     percentage of net revenue, as defined. As of December 31, 1997, the 
     Company had repaid approximately $2.9 million of principal under the 
     T.E.P. Financing. Interest was payable monthly and accrued at a 
     combination of LIBOR plus 4.5% and New York prime plus certain basis 
     points based on the specific borrowing. At December 31, 1997, the 
     blended effective interest rate accruing on the loans was 15% per annum. 
     The loan was collateralized by the oil and gas properties and the stock 
     of the Company.

     The T.E.P. Financing contained financial covenants, the most restrictive of
     which pertained to the payment of dividends, distributions to shareholders
     and the Company's working capital ratio. The T.E.P. Financing also
     contained administrative covenants. Except for violations of certain
     administrative covenants during the year ended December 31, 1997, the
     Company was in compliance with the covenants of the T.E.P. Financing.
     Regarding the violations of such administrative covenants, the Company
     obtained a waiver from the lender of the T.E.P. Financing which agreed not
     to assert any default based upon such violations unless they existed after
     April 15, 1998.

     On April 2, 1998, a portion of the proceeds from the sale of the Senior
     Notes was used to pay outstanding borrowings under the T.E.P. Financing
     amounting to approximately $28 million and repurchase the Net Profits
     Interest for $11 million. On April 2, 1998, the T.E.P. Financing was
     extinguished, and the unamortized balance of the notes payable discount,
     the deferred debt issuance costs and certain fees incurred at closing were
     written off and reflected in the income statement as an extraordinary loss,
     net of taxes. The effective interest rate accruing on the loans through the
     date of extinguishment in 1998 was 12.8%.

     CREDIT FACILITY

     In May 1998, the Company entered into a four-year credit facility with 
     Christiania Bank og KreditKasse ("Christiania") as lender and 
     administrative agent, pursuant to the terms of that certain Credit 
     Agreement dated effective as of May 15, 1998 (the "Credit Facility"). 
     The Credit Facility provides for loans in an outstanding principal 
     amount not to exceed $50.0 million at any one time, subject to a 
     borrowing base to be determined semi-annually by the administrative 
     agent (the initial borrowing base was $30.0 million), and the issuance 
     of letters of credit in an outstanding face amount not to exceed $6.0 
     million at any one time with the face amount of all outstanding letters 
     of credit reducing, dollar-for-dollar, the availability of loans under 
     the Credit Facility. The initial borrowing base was increased by $5 
     million to a total of $35 million. However, effective April 1, 1999, the 
     borrowing base was reduced to $23 million. Under the Credit Facility, 
     the principal balance outstanding is due and payable on May 28, 2002, 
     and each letter of credit shall be reimbursable by the Company when 
     drawn, or if not then otherwise reimbursed, paid pursuant to a loan 
     under the Credit Facility. Commencing on October 31, 1999, and 
     continuing until its stated maturity, the maximum amount available for 
     borrowings and letters of credit under the Credit Facility will not only 
     be adjusted (increased or decreased, as applicable) by the semi-annual 
     borrowing base determination, but also (i) decreased by monthly mandatory 
     reductions in the borrowing base of $1.5 


                                      40
<PAGE>

     NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


     million per month and (ii) adjusted for sales of collateral having an 
     aggregate value exceeding the lesser of $4.0 million per year or 5% of the
     Company's total proved reserve values. Both the Company and Christiania 
     may initiate two unscheduled redeterminations of the borrowing base 
     during any consecutive twelve-month period. No assurance can be given 
     that the bank will not elect to redetermine the borrowing base in the 
     future. If the sum of the outstanding principal and letters of credit 
     (both drawn and undrawn) exceeds the borrowing base, the Company shall, 
     within 30 days, either repay such excess in full or provide additional 
     collateral acceptable to Christiania. At March 31, 1999, the Company had 
     $23 million of outstanding indebtedness under the Credit Facility.

     The interest rate for borrowings under the Credit Facility are 
     determined at either (i) the ABR rate, or (ii) the Eurodollar Rate plus 
     2.25%, at the election of the Company. The "ABR" rate is the higher of 
     (i) Christiania Bank's prime rate then in effect plus 0.5%, (ii) the 
     secondary market rate for three-month certificates of deposit plus 1.5% 
     or (iii) the federal funds rate then in effect plus 1.0%. The effective 
     interest rate under the Credit Facility for the year ended December 31, 
     1998 was 6.8%. Interest is due on a quarterly basis. The Credit Facility 
     is collateralized by substantially all of the oil and natural gas assets 
     of the Company, including accounts receivable, equipment and gathering 
     systems. The proceeds of the Credit Facility may be used to finance 
     working capital needs and for general corporate purposes of the Company 
     in the ordinary course of its business.

     The Credit Facility contains certain covenants by the Company, including 
     (i) limitations on additional indebtedness and on guaranties by the 
     Company except as permitted under the Credit Facility, (ii) limitations 
     on additional investments except those permitted under the Credit 
     Facility and (iii) restrictions on dividends or distributions or on 
     repurchases or redemptions of capital stock by the Company except for 
     those involving repurchases of MHI capital stock which may not exceed 
     $500,000 in any fiscal year. The Credit Facility requires the Company to 
     maintain and comply with certain financial covenants and ratios, 
     including a minimum interest coverage ratio, a minimum current ratio and 
     a covenant requiring that the Company's general and administrative 
     expenses may not exceed 12.5% of the Company's gross revenues in a 
     calendar year. The Company was in violation of certain administrative 
     and one financial covenant of the Credit Facility as of December 31, 1998.
     The Company has obtained a waiver with respect to those violations, from 
     the lender of the Credit Facility, which agreed not to assert any default
     based upon such violations. The Company and the lender have entered into a
     First Amendment to the Credit Facility to amend certain financial covenants
     and the effective interest rate under the Credit Facility.

4.   FEDERAL INCOME TAXES:

     The components of the net deferred taxes are as follows (in thousands):

<TABLE>
<CAPTION>
                                                                              DECEMBER 31,
                                                                          -------------------
                                                                            1997        1998
                                                                          -------    --------
                  <S>                                                     <C>        <C>
                  Deferred tax assets:
                    Net operating loss carryforward                       $ 3,242    $  6,613
                    Other                                                      30          46
                                                                          -------    --------

                      Total deferred tax asset                              3,272       6,659
                                                                          -------    --------

                  Deferred tax liabilities: 
                    Oil and gas properties                                 (5,063)     (4,774)
                    Other                                                                  (9)
                                                                          -------    --------

                      Total deferred tax liability                         (5,063)     (4,783)
                                                                          -------    --------

                      Net deferred taxes                                  $(1,791)   $  1,876
                                                                          =======    ========
</TABLE>

     At December 31, 1998, the Company had a net operating loss carryforward 
     of approximately $19.5 million, which begins expiring in 2017. 
     Utilization of the net operating loss carryforward is subject to annual 
     limitations due to certain stock ownership changes that have occurred or 
     may occur. Realization of deferred tax assets associated with the net 
     operating loss carryforward is dependent upon generating sufficient 
     taxable income prior to their expiration. Management believes it is more 
     likely than not that future taxable income generated will be sufficient 
     to recover the net operating loss prior to expiration. Estimates of 
     taxable income are significantly effected by changes in oil and gas 
     prices, estimates of future production, and estimates of operating and 
     capital costs. The net deferred tax assets could be reduced in the near 
     term if management's estimates of taxable income during the carryforward 
     period are significantly reduced. 


                                      41

<PAGE>

     NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


     Income tax expense (benefit) differs from the amount that would be provided
     by applying the statutory U.S. federal income tax rate to (loss) income
     before income taxes for the following reasons (in thousands):

<TABLE>
<CAPTION>
                                                                   YEAR ENDED DECEMBER 31,
                                                                ----------------------------
                                                                 1996      1997        1998
                                                                ------     ----      -------
          <S>                                                   <C>        <C>       <C>
          Computed statutory tax (benefit) expense at 34%       $ (304)     $ 1      $(4,826)
          Changes in taxes resulting from:
            Section 29 credits                                     (13)
            Conversion to C corporation status                   2,032       
            Permanent differences                                            10          (11)
            Other                                                   65                  (115)
                                                                ------     ----      -------

              Total income tax expense (benefit)                $1,780      $11      $(4,952)
                                                                ======     ====      =======
</TABLE>


5.   HEDGING ACTIVITIES:

     In an effort to achieve more predictable cash flows and earnings and reduce
     the effects of volatility of the price of oil and natural gas on the
     Company's operations, the Company has hedged in the past, and in the future
     expects to hedge oil and natural gas prices through the use of swaps, put
     options and costless collars. While the use of these hedging arrangements
     limits the downside-risk of adverse price movements, it also limits future
     gains from favorable movements.

     The annual average oil and natural gas prices received by the Company 
     have fluctuated significantly over the past three years. Approximately 
     54%, 72% and 48% of the Company's production was hedged during the years 
     ended December 31, 1996, 1997 and 1998, respectively. The Company's 
     weighted average natural gas price received per Mcf (including the 
     effects of hedging transactions) was $2.15, $2.33 and $2.07 during the 
     years ended December 31, 1996, 1997 and 1998, respectively. Hedging 
     transactions resulted in a ($0.24), ($0.32) and $0.01 increase 
     (reduction) in the Company's weighted average natural gas price received 
     per Mcf in 1996, 1997 and 1998, respectively. The unrealized (loss) gain 
     related the hedging contracts was ($1.1 million), ($1.1 million) and 
     $2.1 million as of December 31, 1996, 1997, and 1998, respectively.

     As of December 31, 1998, the Company had entered into commodity price
     hedging contracts with respect to its gas production for 1999 and 2000 as
     follows:

<TABLE>
<CAPTION>
                                                              PRICE PER MMbtu
                                             ------------------------------------------------
                                                         COLLAR
                               VOLUME IN     -------------------------------
         PERIOD                  MMbtu           FLOOR            CEILING        STRIKE PRICE
-------------------------      ---------     -------------     -------------     ------------
<S>                            <C>           <C>               <C>               <C>
Jan 1999 - Dec 1999
Put option                       600,000                                            $2.25
Costless collar                1,800,000         $2.25            $2.99
Costless collar                1,800,000         $2.00            $2.22
Costless collar                2,400,000         $2.15            $2.38
Costless collar                1,800,000         $1.98            $2.22
Costless collar                1,200,000         $2.15            $2.36

Jan 2000 - April 2000
Costless collar                  600,000         $2.00            $2.22
Costless collar                1,200,000         $2.15            $2.38
Costless collar                  600,000         $1.98            $2.22
Costless collar                  600,000         $2.15            $2.36
</TABLE>


     These hedging transactions are settled based on settlement prices 
     relative to a Houston Ship Channel Index. With respect to any particular 
     costless collar transaction, the counterparty is required to make a 
     payment to the Company if the settlement price for any settlement period 
     is below the floor price for such transaction, and the Company is 
     required to make payment to the counterparty if the settlement price for 
     any settlement period is above the ceiling price for such transaction. 
     For put options, the counterparty is required to make payment to the 
     Company if the settlement price for any settlement period is below the 
     strike price for such transaction. The Company is not required to make 
     any payment in connection with the settlement of put options. The 
     premium paid by the Company for the option was approximately $229,500. 
     As of December 31, 1998, approximately $76,500 remains unamortized.
                                       


                                      42
<PAGE>

     NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


6.   EMPLOYEE BENEFIT PLANS:

     STOCK OPTIONS

     On July 1, 1998, the shareholders of MHI approved the Michael Holdings, 
     Inc. 1998 Stock Option Plan ("1998 Plan"). The 1998 Plan is available 
     for grants to substantially all employees and directors of MHI and the 
     Company. The 1998 Plan is administered by the Compensation Committee of 
     the Board of Directors of MHI and the Company. A maximum of 194,000 shares 
     of MHI common stock is available for grant under the 1998 Plan. As of 
     December 31, 1998, MHI granted, at exercise prices in excess of the fair 
     market value per share, options covering a total of 73,350 shares to 22 
     employees and directors of the Company. Options that have been granted 
     and are outstanding generally expire 10 years from the date of grant and 
     become exercisable at the rate of 33.33% per year. The following is a 
     summary of all stock options activity for 1998. The Company did not have 
     a stock option plan in 1996 and 1997.

<TABLE>
<CAPTION>
                                                        NUMBER OF        WEIGHTED
                                                         SHARES           AVERAGE
                                                       UNDERLYING        EXERCISE
                                                        OPTIONS           PRICE
                                                       ----------        --------
       <S>                                             <C>               <C>
       Outstanding at December 31, 1997                       -                -

       Granted                                           73,350          $ 78.35
       Exercised                                              -                -
       Forfeited                                              -                -
                                                         ------          -------

       Outstanding at December 31, 1998                  73,350          $ 78.35
                                                         ======          =======
       Exercisable at December 31, 1998                       -                -
                                                         ======          =======
</TABLE>


     At December 31, 1998, the Company had an additional 120,650 shares 
     available for grants of options under the 1998 Plan. If granted, these 
     additional options will be exercisable at a price not less than the fair 
     market value per share of the Company's Common Stock on the date of 
     grant. The weighted average fair value of options granted during 1998 
     was $18.12.

     The fair value of each stock option granted is estimated as of the date of
     grant using the Black-Scholes option-pricing model with the following
     weighted-average assumptions for grants in 1998: no dividend yield;
     expected volatility of 0.00%; risk-free interest rates of 5.40% and an
     expected option life of 5 years.

     The following table summarizes information about stock options outstanding
     and exercisable at December 31, 1998:

<TABLE>
<CAPTION>
                              OPTIONS OUTSTANDING                                        OPTIONS EXERCISABLE
     ---------------------------------------------------------------------     -----------------------------------
     <S>               <C>             <C>                  <C>                <C>               <C>
                                           WEIGHTED
                                           AVERAGE
          EXERCISE                        REMAINING
           PRICE       OUTSTANDING     CONTRACTUAL LIFE     EXERCISE PRICE        EXERCISABLE     EXERCISE PRICE

          $ 78.35         73,350            9.52               $ 78.35                 -                 -
</TABLE>

     Common Stock issued through the exercise of stock options results in a tax
     deduction for the Company equivalent to the taxable gain recognized by the
     optionee. For financial reporting purposes, the tax effect of this
     deduction is accounted for as a credit to additional paid-in capital rather
     than as a reduction of income tax expense. There were no exercises of
     options as of December 31, 1998.
                                       


                                      43

<PAGE>

     NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


     If the fair value based method of accounting in Statement of Financial
     Accounting Standards No. 123, "Accounting for Stock-Based Compensation"
     ("SFAS 123") had been applied, the Company's net loss for 1998 would 
     have approximated the pro forma amount below (in thousands):

<TABLE>
<CAPTION>
                                           YEAR ENDED
                                       DECEMBER 31, 1998
                                       -----------------
     <S>                               <C>
     Net loss - as reported                $ (9,241)
     Net loss - pro forma                  $ (9,380)
</TABLE>


     The effects of applying SFAS 123 in this pro forma disclosure are not
     indicative of future amounts as the Company anticipates making awards in
     the future under its stock-based compensation plans.

     401(k) PLAN

     The Company sponsors a 401(k) profit sharing plan (the "401(k) Plan") under
     Section 401(k) of the Internal Revenue Code, which covers all employees of
     the Company, subject to eligibility conditions. Effective August 1, 1998,
     the Company, began to match $0.50 for each $1.00 of employee deferral, with
     the Company's contribution not to exceed 6% of an employee's salary,
     subject to limitations imposed by the Internal Revenue Code. The Company's
     contributions amounted to approximately $18,000 for the year ended December
     31, 1998. The Company did not make any contributions to the 401(k) Plan 
     during the years ended December 31, 1996 and 1997.



7.   RECENT ACCOUNTING PRONOUNCEMENT:

     In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative 
     Instruments and Hedging Activities", ("SFAS 133") which is effective for 
     fiscal years beginning after June 15, 1999. SFAS 133 establishes 
     accounting and reporting standards for derivative instruments, including 
     certain derivative instruments embedded in other contracts, and for 
     hedging activities. It also requires that an entity recognize all 
     derivatives as either assets or liabilities in the statement of 
     financial position and measure those items at fair value. If certain 
     conditions are met, a derivative may be specifically designated as (a) a 
     hedge of the exposure to changes in the fair value of a recognized asset 
     or liability or an unrecognized firm commitment, (b) a hedge of the 
     exposure to variable cash flows of a forecasted transaction, or (c) a 
     hedge of the foreign currency exposure of a net investment in a foreign 
     operation, an unrecognized firm commitment, an available-for-sale 
     security, or a foreign-currency-dominated forecasted transaction. For a 
     derivative designated as hedging the exposure to variable cash flows of 
     a forecasted transaction (referenced to as a cash flow hedge), the 
     effective portion of the derivative gain or loss is initially reported 
     as a component of other comprehensive income (outside earnings) and 
     subsequently reclassified into earnings when the forecasted transaction 
     affects earnings. The ineffective portion of the gain or loss is 
     reported in earnings immediately. The extent of the impact of adopting 
     SFAS 133 on the Company's financial position, results of operations, or 
     cash flows will be a function of the open derivative contracts at the 
     date of adoption. As of December 31, 1998, the Company can not estimate 
     the impact of SFAS 133 on its future consolidated financial position, 
     results of operations or cash flows.

8.   RELATED PARTY TRANSACTIONS AND SIGNIFICANT CONCENTRATIONS:

     Beginning in April 1996, the Company entered into an agreement, 
     continuing thereafter on a quarterly basis subject to termination by 
     either party, with Upstream Energy Services ("Upstream") whereby 
     Upstream purchases all of the gas produced by the Company at spot market 
     prices. The chairman of the board and chief executive officer ("CEO") of 
     the Company had an ownership interest in Upstream until August 1997. 
     Upstream executed a promissory note in an aggregate principal amount of 
     $20,000 payable to the Company's chairman of the board and chief 
     executive officer in connection with the purchase of his interest. 
     Interest on the indebtedness accrues at a rate of 8.25% per annum. 

     Effective November 1, 1998, the Company entered into a new agreement 
     with Upstream. Under the terms of the agreement, the Company pays 
     Upstream a marketing fee as follows:

<TABLE>
<CAPTION>
          VOLUMETRIC TIER (MMBTU/DAY)     MARKETING FEE
          ---------------------------     -------------
          <S>                             <C>
          1. First 20,000                 $0.03/MMbtu


                                      44

<PAGE>

     NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

          2. 20,001 to 40,000             $0.02/MMbtu

          3. All volumes over 40,000      $0.01/MMbtu
</TABLE>

     The Sales Agreement is effective for a one-year period and is renewable
     quarterly thereafter, subject to either party giving 60 days written notice
     of termination.

     Marketing fees paid to Upstream were approximately $106,000, $220,000 
     and $253,000 for the years ended December 31, 1996, 1997 and 1998, 
     respectively. During the years ended December 31, 1996, 1997 and 1998, 
     Upstream purchased gas produced by the Company for approximately $3.2 
     million, $9.7 million and $20.8 million, respectively. At December 31, 
     1996, 1997 and 1998, receivables from Upstream of approximately $2.1 
     million, $3.9 million and $5.2 million respectively, were included in 
     accrued oil and gas sales in the balance sheet. The Company believes the 
     revenues received were equivalent to those that would be paid under an 
     arms-length transaction in the normal course of business.

     In July 1997, the Company executed in writing a verbal agreement which 
     had granted to the vice president of geosciences of the Company a 1.5% 
     of 8/8ths overriding royalty interest in leases acquired either directly 
     or indirectly by the Company or its affiliates in Webb County or Zapata 
     County, Texas. This overriding royalty interest expires upon the death 
     of the vice president or upon his termination, resignation or retirement 
     from the Company. The overriding royalty interest does not apply to any 
     producing properties acquired by the Company except for deepenings or 
     sidetracks of existing wells and/or all new wells drilled on the 
     acquired producing properties. For the year ended December 31, 1996, 
     1997 and 1998, the Vice President of geosciences received from the 
     Company approximately $33,000, $105,000 and $275,000, respectively, 
     under the overriding royalty interests.

     On June 10, 1997, the Chairman of the Board and CEO of the Company, 
     entered into an agreement with the Company pursuant to which he granted 
     the Company an option to purchase his undivided two-thirds working 
     interest in a leasehold interest. The Company exercised this option and 
     purchased the lease.  The leasehold interest expires on May 30, 2000 and 
     covers approximately 750 acres in Webb County, Texas. The exercise price 
     of the option was $87,500.  In addition, pursuant to the agreement, the 
     Chairman of the Board and CEO reserved a 1% overriding royalty interest.

     In December 1998, the Company loaned $1.5 million to a joint venture
     between a Mexican construction company and a Texas limited liability 
     company that participates in the drilling of natural gas wells for 
     Petroleos Mexicanos ("Pemex") in the Burgos Basin of Northern Mexico. 
     The Mexican construction company has a 51% ownership interest in the 
     joint venture and the Texas limited liability company has a 49% 
     ownership interest. The note receivable is due December 1999 and bears 
     interest at 12%. The Company has the option to convert the note 
     receivable to a 50% equity interest in the Texas limited liability 
     company.



9.   SUPPLEMENTAL CASH FLOW INFORMATION:

     Cash payments for interest are as follows (in thousands):

<TABLE>
<CAPTION>
                                                                                            YEAR ENDED DECEMBER 31,
                                                                                   ---------------------------------------
                                                                                   1996             1997              1998
                                                                                   ----             ----              ----
        <S>                                                                        <C>             <C>               <C>
        Interest payments (net of interest capitalized of $217, $574,
        and $1,440 during 1996, 1997, and 1998, respectively)                      $833            $1,626            $7,677

     Non-cash investing and financing transactions not reflected in the
     statement of cash flows include the following (in thousands):

                                                                                           YEAR ENDED DECEMBER 31,
                                                                                   1996             1997              1998
                                                                                   ----             ----              ----
          Changes in accounts payable related to capital expenditures              $238            $ 465             $5,225
          Increase of oil and gas properties due to recognition of
            deferred tax liabilities from acquired properties                                                         1,285
          Transfer of oil and gas properties as repayment
            Of note payable to a limited partnership                              4,791         
          Adjustment to purchase price of certain oil and gas properties            420         
</TABLE>



                                      45

<PAGE>

     NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


10.  COMMITMENTS AND CONTINGENCIES:

     LEASES

     The Company has entered into a noncancelable operating lease agreement for
     office space in Houston, Texas. The lease term expires in 2004, with two
     options to renew the lease for a period of five years each. Future minimum
     lease payments required as of December 31, 1998 related to noncancelable
     operating leases are as follows:

<TABLE>
<CAPTION>
          YEAR ENDED DECEMBER 31,
          -----------------------
          <S>                            <C>
                   1999                  $144,583
                   2000                   144,583
                   2001                   157,075
                   2002                   163,321
                   2003                   114,159
                   2004                    56,011
                                         --------
                                         $779,732
                                         ========
</TABLE>

     Rent expense for the years ended December 31, 1996, 1997 and 1998 was
     approximately $50,000, $69,000 and $154,000, respectively.

     LEGAL PROCEEDINGS

     The Company has been and may in the future be involved as a party in
     various legal proceedings, which are incidental to the ordinary course of
     business. Management of the Company regularly analyzes current information
     and, as necessary, provides accruals for probable liabilities on the
     eventual disposition of these matters. In the opinion of management and
     legal counsel, as of December 31, 1998, there were no threatened or pending
     legal matters which would have a material impact on the Company's
     consolidated financial position, results of operations or cash flows.

     OTHER MATTERS

     In conjunction with the 1996 Acquisition, Conoco (as the successor in 
     interest to the seller) and the Company entered into a Gas Exchange 
     Agreement whereby such parties agreed that the Company would deliver to 
     Conoco all of the natural gas produced from the leases acquired in the 
     1996 Acquisition at the point(s) at which such gas enters the transmission
     pipelines owned by Lobo Pipeline Company ("Lobo Pipeline") (the 
     "delivery point") in exchange for natural gas in the same quantity and 
     quality delivered by Conoco at the Agua Dulce hub near Corpus Christi, 
     Texas. The parties' obligations under the Gas Exchange Agreement are 
     subject to the natural gas delivered and the pipeline meeting certain 
     specifications. The title to the Company gas vests in Conoco at the 
     delivery point, except to the extent such amount exceeds the amount of 
     redelivered gas at the redelivery point, in which case the Company 
     retains title and ownership of such excess, which is then transported by 
     Lobo Pipeline pursuant to an Interruptible Gas Transportation Agreement. 
     The consideration received by Lobo Pipeline is $0.17 per Mcf for 
     compression, transportation and dehydration.

11.      DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES:

     CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES

<TABLE>
<CAPTION>
                                                                             DECEMBER 31,
                                                                        ----------------------
                                                                          1997          1998
                                                                        -------      ---------
     <S>                                                                <C>          <C>
     Unproved oil and gas properties                                    $ 1,247      $  14,496
     Proved oil and gas properties                                       33,447        140,490
     Other                                                                  283            881
                                                                        -------      ---------
                                                                         34,977        155,867
     Accumulated depreciation, depletion and amortization                (6,966)       (24,989)
                                                                        -------      ---------
                                                                        $28,011      $ 130,878
                                                                        =======      =========
</TABLE>



                                       46
<PAGE>

     NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


     COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES

     Costs incurred for oil and gas property acquisition, exploration and
     development activities, whether capitalized or expensed, are as follows 
     (in thousands):

<TABLE>
<CAPTION>
                                                  YEAR ENDED DECEMBER 31
                                              ------------------------------
                                                1996       1997       1998
                                              -------    -------    --------
     <S>                                      <C>        <C>        <C>
     Property acquisition:
       Unproved                               $ 2,929    $   355    $ 15,183
       Proved                                   9,554      2,425      78,458
     Development                                2,757     12,074      25,295
     Interest capitalized                         217        574       1,440
                                              -------    -------    --------
               Total costs incurred           $15,457    $15,428    $120,376
                                              =======    =======    ========
</TABLE>


     SALES OF OIL AND GAS

     Substantially all of the Company's natural gas is sold to one purchaser
     (see Note 8). Substantially all of the Company's oil and condensate is sold
     to two customers.

     OIL AND GAS RESERVE QUANTITIES (UNAUDITED)

     Users of this information should be aware that the process of estimating
     quantities of "proved" and "proved developed" natural gas and crude oil
     reserves is very complex, requiring significant subjective decisions in the
     evaluation of all available geological, engineering and economic data for
     each reservoir. The data for a given reservoir may also change
     substantially over time as a result of numerous factors including, but not
     limited to, additional development activity, evolving production history
     and continual reassessment of the viability of production under varying
     economic conditions. Consequently, material revisions to existing reserve
     estimates occur from time to time. Although every reasonable effort is made
     to ensure that reserve estimates reported represent the most accurate
     assessments possible, the significance of the subjective decisions required
     and variances in available data for various reservoirs make these estimates
     generally less precise than other estimates presented in connection with
     financial statement disclosures.

     The reserve information as of December 31, 1996, 1997 and 1998 was prepared
     by Huddleston & Co., Inc. The Company emphasizes that reserve estimates are
     inherently imprecise and that estimates of new discoveries are more
     imprecise than those of proved producing oil and gas properties.
     Accordingly, these estimates are expected to change as future information
     becomes available.

     Proved reserves are estimated quantities of natural gas, crude oil and
     condensate that geological and engineering data demonstrate, with
     reasonable certainty, to be recoverable in future years from known
     reservoirs under existing economic and operating conditions. Proved
     developed reserves are proved reserves that can be expected to be recovered
     through existing wells with existing economic and operating methods.

     No major discovery or other favorable or adverse event subsequent to
     December 31, 1998 is believed to have caused a material change in the
     estimates of proved or proved developed reserves as of that date.



                                      47
<PAGE>

     NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


     The following table sets forth the Company's net proved reserves, including
     the changes therein, and proved developed reserves (all within the United
     States) at the end of each of the three years in the period ended December
     31, 1998:

<TABLE>
<CAPTION>
                                                                      CRUDE OIL      NATURAL
                                                                        (MBBl)      GAS (MMcf)
                                                                      ---------     ----------
          <S>                                                         <C>           <C>
          Proved developed and undeveloped reserves: 
            January 1, 1996                                              2,260          5,909
              Revision of previous estimates                                --          5,920
              Extensions, discoveries and other additions                    9          2,299
              Production                                                   (37)        (1,324)
              Sales of minerals in place                                (2,182)            --
              Purchases of reserves in place                               189         36,442
                                                                        ------         ------

            December 31, 1996                                              239         49,246
                                                                        ------         ------

              Revision of previous estimates                               (38)        (6,848)
              Extensions, discoveries and other additions                   70          9,105
              Production                                                   (21)        (3,685)
              Purchases of reserves in place                                15          3,347
                                                                        ------         ------

            December 31, 1997                                              265         51,165
                                                                        ------         ------

              Revision of previous estimates                              (144)       (15,128)
              Extensions, discoveries and other additions                  411         56,116
              Production                                                   (79)       (10,510)
              Sales of minerals in place                                    (4)          (716)
              Purchases of reserves in place                             4,474        108,826
                                                                        ------         ------

            December 31, 1998                                            4,923        189,753
                                                                        ======        =======


                                                                      CRUDE OIL      NATURAL
                                                                        (MBBl)      GAS (MMcf)
                                                                      ---------     ----------
          Proved developed reserves:
            December 31, 1995                                              689          2,627
            December 31, 1996                                               79         16,924
            December 31, 1997                                              108         22,937
            December 31, 1998                                              904         54,277
</TABLE>


     STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO 
     PROVED OIL AND GAS RESERVES (UNAUDITED)

     SFAS No. 69 prescribes guidelines for computing a standardized measure of
     future net cash flows and changes therein relating to estimated proved
     reserves. The Company has followed these guidelines which are briefly
     discussed below.

     Future cash inflows and future production and development costs are
     determined by applying year-end prices and costs to the estimated
     quantities of oil and gas to be produced. Estimated future income taxes are
     computed using current statutory income tax rates, including consideration
     for estimated future statutory depletion and alternative fuels tax credits.
     The resulting future net cash flows are reduced to present value amounts by
     applying a 10% annual discount factor.

     The assumptions used to compute the standardized measure are those
     prescribed by the Financial Accounting Standards Board and, as such do not
     necessarily reflect the Company's expectations of actual revenues to be
     derived from those reserves nor their present worth. The limitations
     inherent in the reserve quantity estimation process, as discussed
     previously, are equally applicable to the standardized measure computations
     since these estimates are the basis for the valuation process.

     The standardized measure of discounted future net cash flows relating to
     proved oil and gas reserves is as follows (in thousands):


                                      48
<PAGE>

     NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
                                                                                           AS OF DECEMBER 31,
                                                                              -----------------------------------------
                                                                                1996             1997            1998
                                                                              --------         --------        --------
          <S>                                                                 <C>              <C>             <C>
          Future cash inflows                                                 $129,588         $115,766        $396,091
            Less related future: 
              Production costs                                                 (19,319)         (20,226)        (74,723)
              Development costs                                                (16,070)         (17,295)        (92,504)
              Income tax expense                                               (28,715)         (22,497)        (38,182)
                                                                              --------         --------        --------

          Future net cash flows                                                 65,484           55,748         190,682
          10% annual discount for estimating timing of cash flows              (23,135)         (19,109)        (80,172)
                                                                              --------         --------        --------

          Standardized measure of discounted future net cash flows            $ 42,349         $ 36,639        $110,510
                                                                              ========         ========        ========
</TABLE>


     A summary of the changes in the standardized measure of discounted future
     net cash flows applicable to proved oil and gas reserves is as follows (in
     thousands):

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

          Beginning of the period                                             $ 12,877         $ 42,349        $ 36,639
                                                                              --------         --------        --------

          Revisions of previous estimates:                                                                       
            Changes in prices and costs                                         17,803           (9,701)         (8,241)
            Changes in quantities                                                9,108          (12,789)        (19,637)
          Development costs incurred during the period                              96            1,836           2,400
          Additions to proved reserves resulting from extensions
            and discoveries, less related costs                                  2,051           11,172          31,001
          Purchases of reserves in place                                        31,082            3,894          83,040
          Sales of reserves in place                                           (11,983)                            (729)
          Accretion of discount                                                  1,851            6,073           5,149
          Sales of oil and gas, net of production costs                         (1,663)          (7,269)        (18,262)
          Net change in income taxes                                           (12,744)           3,530          (7,280)
          Production timing and other                                           (6,129)          (2,456)          6,430
                                                                              --------         --------        --------
          Net increase (decrease)                                               29,472           (5,710)         73,871

          End of the period                                                   $ 42,349         $ 36,639        $110,510
                                                                              ========         ========        ========
</TABLE>



                                      49

<PAGE>

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND 
FINANCIAL DISCLOSURE

     Not Applicable
                                       
                                    PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

         The following table sets forth the names, ages and positions of the 
directors and executive officers of the Company. A summary of the background 
and experience of each of these individuals is set forth following the table.

<TABLE>
<CAPTION>
NAME                           AGE                  POSITION WITH COMPANY
----                           ---                  ---------------------
<S>                            <C>    <C>
Glenn D. Hart                   42    Chairman of the Board and Chief Executive Officer
Michael G. Farmar               41    President, Chief Operating Officer and Director
Jerry F. Holditch               41    Vice President-Geosciences and Director
Douglas R. Fogle                43    Vice President-Engineering
Robert L. Swanson               41    Vice President-Finance
Scott R. Sampsell               42    Vice President, Controller, Treasurer and Secretary
Jim R. Smith                    59    Director
Jack I. Tompkins                53    Director
Bryant H. Patton                41    Director
</TABLE>


         Glenn D. Hart served as President of the Company from its inception 
in 1982 until August 1996, when he was elected to his current position as 
Chairman of the Board and Chief Executive Officer. From 1980 to 1983, Mr. 
Hart was an engineering manager with Sanchez-O'Brien Oil & Gas Corporation, 
an independent exploration and production company in South Texas. From 1978 
to 1980, he held several engineering positions with Tenneco Oil Company's 
Gulf Coast District. Mr. Hart has a B.S. in petroleum engineering from Texas 
A&M University.

         Michael G. Farmar has served as President and Director of the 
Company since August 1996 and was elected Chief Operating Officer in January 
1997. From January 1995 to August 1996, Mr. Farmar served as a financial 
advisor to small independent oil companies. In 1988, Mr. Farmar joined 
Odyssey Petroleum Company, where, as General Manager, he was responsible for 
operational and financial functions of the company until it was sold in 1994. 
As an analyst for Maxus Exploration Company from 1986 until 1988, Mr. Farmar 
worked on mergers, acquisitions and divestitures. From 1984 to 1986, Mr. 
Farmar served in Diamond Shamrock Exploration Company's strategic planning 
group. Mr. Farmar began his career with Chevron U.S.A. in 1980 and held 
drilling and production engineering positions through 1983. Mr. Farmar holds 
a B.S. in petroleum engineering from the University of Southern California 
and an MBA from Southern Methodist University.

         Jerry F. Holditch joined the Company in 1987 and has served as Vice 
President of Geosciences and as Director since that time. From 1982 until 
1987, Mr. Holditch served as a developmental geologist with TransTexas Gas 
Corporation and its predecessors, where he was involved in numerous drilling 
activities in the Lobo Trend area. From 1980 until 1982, Mr. Holditch was 
employed as a Gulf Coast geologist with Gulf Oil Corporation. Mr. Holditch 
holds a B.S. in geology from Texas A&M University.

         Douglas R. Fogle has served as Engineering Manager of the Company 
since 1994 after joining the Company in 1992 as a Production Engineer and was 
appointed to the additional position of Vice President of Engineering in 
October 1998. From 1986 to 1991, Mr. Fogle worked as an insurance agent. From 
1984 to 1986, Mr. Fogle worked with Langham Energy, an independent 
exploration and production company, as Senior Petroleum Engineer. Mr. Fogle 
worked from 1978 through 1984 with Champlin Petroleum (which was subsequently 
acquired by Union Pacific Resources Company), an independent exploration and 
production company, first as a Drilling and Completion Engineer and then, 
starting in 1983, as Staff Production Engineer. Mr. Fogle has a B.S. in 
petroleum engineering from Texas A&M University.

         Robert L. Swanson joined the Company in September 1997 and has 
served as Vice President of Finance since that time. From 1994 until joining 
the Company, Mr. Swanson served as controller, chief financial officer and 
                                       


                                      50

<PAGE>

treasurer of Southwest Ice Enterprises, L.C., a Texas limited liability 
company and the owner and operator of a professional hockey team in Houston, 
Texas. Prior to joining Southwest Ice Enterprises, L.C., Mr. Swanson was 
employed as a public accountant from 1985 to 1994 with two Houston-area 
accounting firms and one San Antonio-area accounting firm. Mr. Swanson is a 
certified public accountant and is a member of the American Institute of 
Certified Public Accountants and the Texas Society of Certified Public 
Accountants.

         Scott R. Sampsell has served as the Company's Controller and 
Treasurer since 1992 and was appointed to the additional positions of Vice 
President and Secretary in April 1998. From 1982 to 1992, Mr. Sampsell worked 
in various accounting supervisory roles with Union Texas Petroleum 
Corporation, an independent exploration and production company, including 
Manager of Financial and Operational Accounting for one of its subsidiaries. 
From 1977 until 1982, Mr. Sampsell worked with Supron Energy Corporation, an 
independent exploration and production company, where he began as staff 
accountant and advanced to Assistant Treasurer.

         Jim R. Smith has served as a Director of the Company since November 
1996. Since 1964, Mr. Smith has managed a privately-owned real estate 
development company headquartered in Houston, Texas, which he founded. Mr. 
Smith is also a private investor and holds positions with several non-profit 
organizations, including Chairman of the Board of Directors of Goodwill 
Industries of Houston.

         Jack I. Tompkins has served as a Director of the Company since July 
1997. Mr. Tompkins is a managing director of Raintree Equity Advisors, L.L.C. 
and is Chairman of the Board of Automotive Realty Trust of America. From 1988 
until October 1996, Mr. Tompkins served as Senior Vice President, Chief 
Information, Administrative and Accounting Officer at Enron Corporation. He 
also served as a member of Enron Corporation's Management Committee from 1989 
through 1996. Mr. Tompkins began his career with Arthur Young & Co., serving 
three years before joining Arthur Andersen, L.L.P., where he was elected to 
the partnership in 1981 and was in charge of the Mergers and Acquisitions 
Program for the Houston office. Mr. Tompkins also serves as chairman of the 
board of Boys and Girls Country of Houston, Inc., and formerly served on the 
board of directors of Bank of America Texas, the Private Sector Council and 
Junior Achievement of Southeast Texas, Inc.

         Bryant H. Patton has served as a Director of the Company since July 
1997. Since 1991, Mr. Patton has been the Vice President of Associated Energy 
Managers ("AEM"), an institutional investment management firm specializing in 
private investments in the energy industry. AEM has invested for its clients 
over $300 million with 23 different independent oil and gas companies through 
three investment partnerships. Mr. Patton's industry experience spans 20 
years including ten years as an equity owner in a fully integrated, 
family-owned, oil and gas producing company consisting at one time of seven 
entities and 350 employees.

ITEM 11.  EXECUTIVE COMPENSATION

         The following table sets forth certain summary information regarding 
compensation paid or accrued by the Company to or on behalf of the Company's 
executive officers (the "Named Executive Officers") for the fiscal years ended
December 31, 1997 and 1998.

                           SUMMARY COMPENSATION TABLE

<TABLE>
<CAPTION>
                                                       ANNUAL COMPENSATION          
                                                      ---------------------         401K          STOCK OPTIONS      ALL OTHER
              PRINCIPAL POSITIONS                      SALARY        BONUS      CONTRIBUTIONS        GRANTED       COMPENSATION
-------------------------------------------------     --------     --------     -------------     -------------    ------------
<S>                                                   <C>          <C>          <C>               <C>              <C>
GLENN D. HART
  Chairman of the Board and Chief Executive Officer   
  1998                                                $238,500     $202,500        $3,038              -0-         $ 10,553 (1)
  1997                                                 144,000        6,000             -              -0-           11,303 (1)
MICHAEL G. FARMAR
  President and Chief Operating Officer                
  1998                                                 165,000      135,000        $2,160              -0-         $  -0-
  1997                                                  84,000        3,500             -              -0-            -0-
JERRY F. HOLDITCH
  Vice President-Geosciences                            
  1998                                                  99,000       75,000        $1,355              -0-         $274,690 (2)
  1997                                                  60,000        2,500           -0-              -0-          104,946 (2)
DOUGLAS R. FOGLE
  Vice President-Engineering                            
  1998                                                  90,900       11,000        $1,262              -0-            1,686 (1)
  1997                                                  63,000        2,625           -0-              -0-            4,023 (1)
SCOTT R. SAMPSELL
  Vice President, Controller, Treasurer and Secretary                                             
  1998                                                  81,300       20,900        $  998              -0-            -0-
  1997                                                  69,450        3,050           -0-              -0-            -0-
</TABLE>

(1)  Represents the estimated value of personal use of a Company vehicle.
(2)  Represents amounts paid or accrued to Mr. Holditch during 1998 
     pursuant to certain overriding royalty interests granted to him.

No options were issued to or exercised by the Named Executive Officers in 1998.


                                      51

<PAGE>

STOCK OPTION AND OTHER EMPLOYEE COMPENSATION PLANS

         In July 1998, MHI adopted the Michael Holdings, Inc. 1998 Stock 
Option Plan (the "Option Plan") pursuant to which incentive stock options as 
defined in the Internal Revenue Code of 1986, as amended ("ISOs"), and 
non-qualified stock options ("NQOs") will be available for grant to key 
employees, consultants and directors of MHI and the Company. The Option Plan 
is administered by the Compensation Committee of the Board of Directors of 
MHI. A maximum of 194,000 shares, subject to adjustment for certain events of 
dilution, is available for grant under the Option Plan. The Option Plan 
provides that the Option Agreement applicable to the grant of options may 
provide that unmatured installments of outstanding options will accelerate 
and become fully vested upon a "change of control" of MHI (as defined in the 
Option Plan).

         As of December 31, 1998, a total of 73,350 options were granted 
under the Option Plan. Grants to employees and directors were granted at an 
exercise price equal to not less than the fair market value per share on the 
date of grant. All such options will have terms of not more than ten years 
and be exercisable in cumulative annual installments of 33.33% of the total 
number of shares subject to the option grants, beginning on the first 
anniversary of the date of grant.

         The Option Plan provides that the plan may be amended or modified by 
the Board of Directors of MHI without the approval of the shareholders of 
MHI, except for any amendment which would increase the total number of shares 
reserved for issuance under the Option Plan or amendments which require 
shareholder approval pursuant to applicable legal requirements or securities 
exchange rules.

OVERRIDING ROYALTY INTERESTS

         The Company has had in place for a number of years an arrangement, 
and by written agreement dated July 24, 1997 the Company formalized such 
arrangement, pursuant to which it has granted to Jerry Holditch, Vice 
President--Exploration and a director of the Company, a 1.5% of 8/8ths 
overriding royalty interest in all leases acquired either directly or 
indirectly by the Company or its affiliates in Webb County or Zapata County, 
Texas. For the year ended December 31, 1996, 1997 and 1998, Mr. Holditch 
received from the Company $32,638, $104,946 and $274,690, respectively, under 
the overriding royalty interests. The overriding royalty interests will not 
apply to any producing properties acquired by the Company except for 
deepenings or sidetracks of existing wells and all new wells drilled on 
acquired producing properties. According to the terms of the agreement 
establishing the overriding royalty interests, the Company's obligation to 
assign overriding royalty interests to Mr. Holditch expires upon the death of 
Mr. Holditch or upon his termination, resignation or retirement from the 
Company; however, any overriding royalty interests assigned prior to such an 
event shall be unaffected by the occurrence of that event. The agreement also 
restricts Mr. Holditch's ability to compete with the Company in the Lobo 
Trend for a period of three years following any resignation or retirement of 
Mr. Holditch from the Company. If, following Mr. Holditch's retirement or 
resignation, the Company becomes financially incapable of drilling or 
completing wells on locations previously identified or selected by Mr. 
Holditch, the Company shall provide written authorization to Mr. Holditch to 
waive the three-year non-competition provision so that Mr. Holditch may 
pursue the development of such location prospects. The Company does not 
anticipate entering into any similar arrangements with any of its officers or 
directors in the future.

EMPLOYMENT AGREEMENTS

         The Company has entered into employment agreements, effective April 
1, 1998, with Glenn D. Hart, Michael G. Farmar and Jerry F. Holditch, 
pursuant to which Mr. Hart will serve as Chief Executive Officer of the 
Company, Mr. Farmar will serve as President of the Company and Mr. Holditch 
will serve as Vice President-Exploration. Each employment agreement is for a 
term of two years and is automatically renewed for a period of two years from 
and after the first day of each calendar quarter, commencing July 1, 1998, 
unless either party gives written notice at least 30 days prior to the end of 
the applicable period. The employment agreements provide for an annual base 
salary ($270,000 for Mr. Hart, $180,000 for Mr. Farmar and $100,000 for Mr. 
Holditch), which amount may be increased subject to periodic reviews. In 
addition, Messrs. Hart, Farmar and Holditch are eligible to receive an annual 
incentive bonus in an amount to be determined by the Board of Directors, but 
in no event will such bonus amount be less than 50% nor more than 100% of the 
employee's annual base salary. The employment agreements of Messrs. Hart and 
Farmar further provide that the employee shall be granted options under the 
Option Plan upon terms and conditions and in an amount to be determined by 
the Compensation Committee. If during the term of the agreement the 
employee's employment with the Company is terminated without "cause" (as 
defined therein) or due to his resignation 
                                       


                                      52

<PAGE>

for "good reason" (as defined therein), the Company will be obligated to pay 
the employee payments in an amount equal to his base salary for the remaining 
term of the agreement plus his accrued but unpaid bonus as of the date of 
termination. The obligations of the Company under the employment agreements 
are guaranteed by MHI.

COMPENSATION OF DIRECTORS

         Non-employee directors of the Company are eligible to receive grants 
of nonqualified stock options to purchase shares of Common Stock pursuant to 
the Option Plan. On August 1, 1998, based on their relative length of service 
as directors, Messrs. Tompkins and Patton were granted options to purchase 
10,000 shares of Common Stock, and Mr. Smith was granted an option to 
purchase 20,000 shares of Common Stock, at exercise prices equal to the fair 
market value of the Common Stock on the date of grant.

         In addition, the Company's non-employee directors receive $2,000 
plus out-of-pocket expenses for each meeting of the Board of Directors that 
they attend.

BOARD COMMITTEES

         Pursuant to the Company's Bylaws, the Board of Directors has 
established standing Audit and Compensation Committees. The Audit Committee 
recommends to the Board the selection and discharge of the Company's 
independent auditors, reviews the professional services performed by the 
auditors, the plan and results of the auditing engagement and the amount of 
fees charged for audit services performed by the auditors and evaluates the 
Company's system of internal accounting controls. The Compensation Committee 
recommends to the Board the compensation to be paid to the Company's 
directors, executive officers and key employees and administers the 
compensation plans for the Company's executive officers and directors. The 
members of the Audit Committee are Messrs. Farmar, Smith and Tompkins. The 
members of the Compensation Committee are Messrs. Smith, Tompkins and Patton.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

         The following table sets forth, as of December 31, 1998, (i) the 
number of shares owned by each person known by the Company to own 
beneficially Common Stock of MHI, (ii) the number of shares owned 
beneficially by each director and (iii) the number of shares owned 
beneficially by all executive officers and directors as a group. MHI owns of 
record all of the issued and outstanding shares of common stock of the 
Company.

<TABLE>
<CAPTION>
                                                               COMMON STOCK
                                                               BENEFICIALLY         PERCENTAGE OF
NAME OF PERSON OR GROUP                                          OWNED(1)             OWNERSHIP
-----------------------                                          --------             ---------
<S>                                                            <C>                  <C>
EXECUTIVE OFFICERS AND DIRECTORS
  Glenn D. Hart                                                  281,900                36.5%
  Michael G. Farmar                                              234,200                30.3%
  Jerry F. Holditch                                               64,500                 8.3%
  Jim R. Smith                                                    80,650                10.4%
  Jack I. Tompkins                                                20,300                 2.6%
  Bryant H. Patton                                                    --                  --
  Scott R. Sampsell                                               24,200                 3.1%
  Douglas R. Fogle                                                34,275                 4.4%
  Robert L. Swanson                                                   --                  --
All executive officers and directors, as a group                 760,525                98.3%
</TABLE>

(1)  Except as otherwise noted, the named shareholder has sole voting, 
     investment and dispositive power.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

         The Company currently markets all of its natural gas through 
Upstream Energy Services, L.L.C. ("Upstream") pursuant to a Natural Gas Sales 
Agreement dated as of November 1, 1998. The Company and the predecessor to 
Upstream had similar marketing arrangements prior to April 1996. During the 
year ended December 31, 1996, 1997 and 1998, the Company paid Upstream or its 
predecessor marketing fees of $106,000, $220,000 and $253,000, respectively, 
under these arrangements. Until August 1997, Glenn D. Hart, the Company's 
Chairman and Chief Executive Officer, owned 20% of the equity securities of 
Upstream and its predecessor. In such capacity, Mr. Hart


                                      53

<PAGE>

received dividends of $26,875 and $6,000 in the year ended December 31, 1996 
and 1997, respectively. Additionally, Upstream executed a promissory note in 
an aggregate principal amount of $20,000 payable to Mr. Hart in connection 
with the purchase by Upstream of Mr. Hart's interest. Interest on the 
indebtedness accrues at a rate of 8.25% per annum. Neither Mr. Hart nor the 
Company or any other officer or director of the Company currently owns any 
interest in Upstream.

         The Company has granted to Jerry F. Holditch, Vice 
President-Exploration and a director of the Company, a 1.5% of 8/8ths 
overriding royalty interest in all leases acquired either directly or 
indirectly by the Company or its affiliates in Webb County and Zapata County, 
Texas.  See Item 11. Executive Compensation.

         On June 10, 1997, Glenn D. Hart, Chairman of the Board and Chief 
Executive Officer of the Company, entered into an agreement with the Company 
pursuant to which Mr. Hart granted the Company an option to purchase an 
undivided two-thirds working interest, which Mr. Hart owns in his individual 
capacity, in a leasehold interest. The Company exercised this option and 
purchased this lease. The leasehold interest expires on May 30, 2000 and 
covers approximately 750 acres in Webb County, Texas. The exercise price of 
the option was $87,500 plus approximately $2,000 in carrying fees. In 
addition, pursuant to the agreement. Mr. Hart reserved a 1% overriding 
royalty interest. 

         Concurrently with the closing of the sale of the Senior Notes, the 
Company acquired, for a purchase price of $11.0 million, the Net Profits 
Interest from Cambrian, at which time Cambrian received a warrant from MHI
to acquire 38,671 shares of Common Stock at an exercise price of $8.00 per 
share. See Item 7. "Management's Discussion and Analysis of Financial 
Condition and Results of Operations--Financing Arrangements."

         Although the Company has no present intention to do so, it may in 
the future enter into other transactions and agreements incidental to its 
business with its directors, officers and principal shareholders. The Company 
intends any such transactions and agreements to be on terms no less favorable 
to the Company than could be obtained from unaffiliated parties on an arms' 
length basis.

         MHI has entered into Indemnity Agreements with each of the directors 
of MHI (who also serve as the directors of the Company), pursuant to which 
MHI has agreed to indemnify each director to the fullest extent permitted 
under the Texas Business Corporation Act. In addition, pursuant to the 
Agreement, MHI shall advance reasonable expenses incurred by each director 
under certain circumstances in any proceeding in which each director was, is 
or is threatened to be named a defendant.

                                     PART IV

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

(a)      1.  CONSOLIDATED FINANCIAL STATEMENTS

         See Index on page 30.

         2.  FINANCIAL STATEMENT SCHEDULES

         None.

                                      54

<PAGE>

         3.  EXHIBITS

         The following instruments are included as exhibits to this report.

<TABLE>
<CAPTION>
         EXHIBIT
         NUMBER                 DESCRIPTION
         ------                 -----------
         <S>        <C>
           3.1*     Articles of Incorporation of the Company.

           3.2*     By-Laws of the Company.

           4.2*     Indenture, dated as of April 2, 1998, between the Company and
                    State Street Bank and Trust Company as Trustee

          10.1***   Michael Holdings, Inc. 1998 Stock Option Plan.

          10.2**    Employment Agreement dated April 1, 1998 between the Company
                    and Glenn D. Hart.

          10.3**    Employment Agreement dated April 1, 1998 between the Company
                    and Michael G. Farmar.

          10.4**    Employment Agreement dated April 1, 1998 between the Company
                    and Jerry F. Holditch.

          10.5*     Purchase and Sale Agreement dated February 20, 1998 by and
                    between the Company and Conoco, Inc.

          10.6*     Purchase and Sale Agreement dated February 5, 1998 by and
                    between the Company and Enron Oil and Gas Company

          10.7*     Stock Purchase Warrant granted by Michael Holdings, Inc. to
                    Cambrian Capital Partners, L.P., dated April 2, 1998.

          10.8*     Form of Indemnification Agreement by and between the Company
                    and its directors.

          10.9*     Assets Agreement dated April 20, 1998 by and between the
                    Company and Mobil Exploration & Producing U.S. Inc. acting as
                    Agent for Mobil Producing Texas & New Mexico Inc.

          10.10*    Oil and Gas Lease dated April 20, 1998 by and between the
                    Company and Mobil Producing Texas & New Mexico Inc.

          10.11*    Warrant to Purchase Shares of Common Stock granted by Michael
                    Holdings, Inc. to Dale L. Schwartzhoff.

          10.12*    First Amended and Restated Shareholders Agreement of the
                    Company.

          10.13*    Credit Agreement dated May 15, 1998 among the Company,
                    Christiania and the lenders named therein.

          10.14*    Master Commodity Swap Agreement dated May 15, 1998 between
                    Christiania and the Company.

          10.15***  Natural Gas Marketing, Transportation and Processing 
                    Agreement dated as of November 1, 1998 by and between the 
                    Company and Upstream Energy Services Company.

          10.16***  First Amendment to Credit Agreement dated March 29, 1999 
                    among the Company, Christiania and the lenders named 
                    therein.

          10.17***  Letter Agreement dated March 30, 1999 between the Company 
                    and Christiania.

          27.1***   Financial Data Schedule.
</TABLE>

   *     Previously filed as an Exhibit (with a corresponding Exhibit number)
         to the Company's Registration Statement on Form S-4 filed May 8, 
         1998, No. 333-52263, and incorporated herein by reference.
   **    Management compensation or incentive plan previously filed.
   ***   Filed herewith.

(b)      REPORTS ON FORM 8-K.

         None.

(c)      EXHIBITS REQUIRED BY ITEM 601 OF REGULATION S-K

         Not applicable.



                                      55
<PAGE>
                                       
                                  SIGNATURES

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

                                      MICHAEL PETROLEUM CORPORATION


Dated: April 1, 1999
                                      By:  /s/ MICHAEL G. FARMAR
                                          -----------------------
                                           Michael G. Farmar
                                           President and Chief
                                           Operating Officer

                                       
                               POWER OF ATTORNEY

         KNOW ALL MEN BY THESE PRESENTS, that each person whose signature 
appears below constitutes and appoints Michael G. Farmar and Glenn D. Hart 
and each of them, as 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 and all documents relating to 
the Annual Report on Form 10-K, for the fiscal year ended December 31, 1998, 
including any and all amendments and supplements thereto, 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 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 as 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 or their or his substitute or substitutes may lawfully do or cause to 
be done by virtue hereof.

PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS 
ANNUAL REPORT ON FORM 10-K HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON 
BEHALF OF THE COMPANY AND IN THE CAPACITIES INDICATED ON THE 1 DAY OF APRIL, 
1999.

<TABLE>
<CAPTION>
          NAME:                                CAPACITIES:
<S>                         <C>
/s/ GLENN D. HART           Chairman of the Board and Chief Executive Officer
---------------------       (Principal Executive Officer)
    Glenn D. Hart           

/s/ MICHAEL G. FARMAR       President, Chief Operating Officer and Director
---------------------
    Michael G. Farmar

/s/ JERRY F. HOLDITCH       Vice President-Geosciences and Director
---------------------
    Jerry F. Holditch

/s/ ROBERT L. SWANSON       Vice President-Finance
---------------------       (Principal Accounting and Financial Officer)
    Robert L. Swanson       

/s/ SCOTT R. SAMPSELL       Vice President-Accounting, Treasurer, and Secretary
---------------------
    Scott R. Sampsell


                                      56
<PAGE>


/s/ JIM R. SMITH            Director
---------------------
    Jim R. Smith

/s/ JACK I. TOMPKINS        Director
---------------------
    Jack I. Tompkins

/s/ BRYANT H. PATTON        Director
---------------------
    Bryant H. Patton
</TABLE>



                                      57