<PAGE>

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                                 UNITED STATES
                      SECURITIES AND EXCHANGE COMMISSION
                            Washington, D.C. 20549

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

                                  FORM 10-K/A

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

                  For the fiscal year ended December 31, 2001

                                      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 0-22650

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

                            PETROCORP INCORPORATED
            (Exact name of registrant as specified in its charter)

                Texas                                  76-0380430
   (State or other jurisdiction of        (I.R.S. Employer Identification No.)
     incorporation organization)

       6733 South Yale Avenue                             74136
           Tulsa, Oklahoma                              (Zip Code)
   (Address of principal executive
              offices)

      Registrant's telephone number, including area code: (918) 491-4500

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

       Securities registered pursuant to Section 12(b) of the Act: None
          Securities registered pursuant to Section 12(g) of the Act:
                    Common Stock, par value $.01 per share
                        Preferred Stock Purchase Rights
                               (Title of class)

   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. [X] Yes [_] No

   Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K ((S)(S)229.045 of this chapter) 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]

   The aggregate market value of the voting stock held by nonaffiliates of the
registrant as of February 28, 2002 was $42,680,916. Indicate the number of
shares outstanding of each of the registrant's classes of common stock, as of
February 28, 2002:

              Common Stock, par value $.01 per share: 12,556,109

                     DOCUMENTS INCORPORATED BY REFERENCE:

   Proxy Statement for the registrant's Annual Meeting of Shareholders to be
held in 2002 (to be filed within 120 days of the close of registrant's fiscal
year) is incorporated by reference into Part III.

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<PAGE>

                               TABLE OF CONTENTS

<TABLE>
<CAPTION>
 Item                                 Title                               Page
 ----                                 -----                               ----

                                    PART I

 <C>    <S>                                                               <C>
     1  Business........................................................    1
     2  Properties......................................................    6
     3  Legal Proceedings...............................................   14
     4  Submission of Matters to a Vote of Security Holders.............   14

                                    PART II

     5  Market for Registrant's Common Equity and Related Stockholder      15
        Matters.........................................................
     6  Selected Financial Data.........................................   16
     7  Management's Discussion and Analysis of Financial Condition and    17
        Results of Operations...........................................
     7A Quantitative and Qualitative Disclosure about Market Risk.......   23
     8  Financial Statements and Supplementary Data.....................   24
     9  Changes in and Disagreements with Accountants on Accounting and    24
        Financial Disclosures...........................................

                                   PART III

 10-13  (Items 10-13 incorporated by reference to Proxy Statement)......   24

                                    PART IV

    14  Exhibits, Financial Statement Schedules, and Reports on Form 8-    25
        K...............................................................
</TABLE>

   As used in this report, "SEC" means the United States Securities and
Exchange Commission, "Bbl" means barrel, "MBbls" means thousand barrels,
"MMBbls" means million barrels, "Mcf" means thousand cubic feet, "MMcf" means
million cubic feet, "Bcf" means billion cubic feet, "BOPD" means barrel of oil
per day, "Mcf/D" means thousand cubic feet per day, "MMcf/D" means million
cubic feet per day, "Mcfe" means natural gas stated on an MCF basis and crude
oil converted to a thousand cubic feet of natural gas equivalent by using the
ratio of one Bbl of crude oil to six Mcf of natural gas, "MMcfe" means million
cubic feet of natural gas equivalents, "Bcfe" means billion cubic feet of
natural gas equivalents, "Tcf" means trillion cubic feet, "PV-10" means
estimated pretax present value of future net revenues discounted at 10% using
SEC rules, "gross" wells or acres are the wells or acres in which the Company
has a working interest, and "net" wells or acres are determined by multiplying
gross wells or acres by the Company's working interest in such wells or acres.
<PAGE>

                                    PART I

Item 1. Business.

General

   PetroCorp Incorporated is an independent energy company engaged in the
acquisition, exploration and development of oil and gas properties, and in the
production of oil, natural gas liquids and natural gas in North America. The
Company's activities are conducted principally in the states of Oklahoma,
Texas, Mississippi, Alabama, Louisiana, Colorado and Kansas, and in the
province of Alberta, Canada.

   At December 31, 2001, the Company's proved reserves totaled 6.4 MMBbls of
oil and 100.0 Bcf of natural gas and had an estimated pretax present value of
future net revenues (PV-10) of $133.2 million. On a Mcfe basis, approximately
74% of the Company's proved reserves were natural gas at such date. In
addition, the Company has unproved interest holdings with a net book value of
$1.2 million, as well as interests in natural gas processing and gathering
facilities with a net book value of $1.5 million.

   The Company was formed in July 1983 as a Delaware corporation and in
December 1986 contributed its assets to a newly formed Texas general
partnership. In October 1992, the Company changed its legal form from a Texas
general partnership to a Texas corporation. In August 1999, the Company signed
a Management Agreement with its largest shareholder, Kaiser-Francis Oil
Company (Kaiser-Francis), under which Kaiser-Francis agreed to provide
management, technical and administrative support for all of the Company's
operations in the United States and Canada. At that time, Gary R. Christopher
was named President and CEO of the Company. Mr. Christopher, who has served on
PetroCorp's Board of Directors since 1996, was an employee of Kaiser-Francis
Oil Company through January 1, 2002, at which time he became an employee of
PetroCorp Incorporated. This Management Agreement was approved by the
shareholders of the Company in October 1999 and took effect on November 1,
1999. A new slate of corporate officers was approved at that time. PetroCorp's
principal executive offices are located at 6733 South Yale Avenue, Tulsa,
Oklahoma 74136, with a mailing address of P.O. Box 21298, Tulsa, Oklahoma
74121-1298, and its telephone number is (918) 491-4500. Unless the context
otherwise requires, the terms the "Company" and "PetroCorp" refer to and
include PetroCorp Incorporated, its predecessor entities (including the
original Delaware corporation and the subsequent Texas general partnership)
and all subsidiaries in which PetroCorp owns a 50% or greater interest.

Business Strategy

   PetroCorp and its wholly-owned Canadian subsidiaries acquire, explore and
develop oil and natural gas properties in North America.

   Acquisition Strategy. The Company has grown, in large part, through the
acquisition of producing oil and gas properties. The Company generally focuses
on acquisitions of long-lived natural gas reserves, located onshore in North
America, and prefers acquisitions that provide additional potential through
development or exploitation efforts, as well as exploratory drilling
opportunities.

   Exploration and Development Strategy. Exploration and development
activities are an important component of PetroCorp's business strategy.
Through its Management Agreement with Kaiser-Francis, the Company has been
able to allocate a greater portion of cash flows to exploration and
development activities.

Acquisition, Exploration and Development Activities

   Merger with Southern Mineral. PetroCorp completed the acquisition of
Southern Mineral on June 6, 2001. Southern Mineral shareholders could elect to
receive .471 shares of PetroCorp common stock or cash of $4.71 or some
combination thereof for each share of Southern Mineral common stock. Based on
elections of Southern Mineral shareholders, PetroCorp issued 4 million shares
(valued at approximately $39 million) and paid cash of approximately $21.4
million. The cash consideration includes cash due to warrant and option
holders, net of cash received from the exercise of Southern Mineral warrants
and options. The totals do not reflect 800,336 shares of

                                       1
<PAGE>

Southern Mineral purchased by PetroCorp in open market transactions prior to
the merger for $3.4 million. See Note 4 to the financial statements for
additional data concerning the merger. 2,190 MBbls of oil and 19,722 MMcf of
gas in the United States and 1,585 MBbls and 12,086 MMcf in Canada were added
through the merger.

   United States. During 2001, the Company participated in a new discovery in
the Cement Field area, located in Caddo County, Oklahoma, increasing proved
reserves by 533 MMcfe. In Lavaca County, Texas, PetroCorp participated in the
successful Barnes well in the Hallettsville field area, adding 482 MMcfe of
proved reserves.

   At year-end 2001, PetroCorp was not participating in any significant
exploratory projects.

   PetroCorp's SW Oklahoma City Unit, which showed positive response to water
injection in 2000, has since flattened in its response. As a result, some
1,297 MBbls have been removed from the proved reserves classification.
PetroCorp recently initiated a tracer program to study the waterflood and is
currently converting additional wells for source water and for water injection
to finish out the waterflood pattern.

   Canada. Recent activity in the Hanlan-Robb area has focused on the
development of the Shaw and Basing areas through the drilling of two new
horizontal wells, adding 1,089 MMcfe of reserves.

Production and Sales

   The following table presents certain information with respect to oil and
gas production attributable to the Company's properties, average sales price
received and average production costs during the three years ended December
31, 2001, 2000, and 1999. The average oil sales and average gas sales have
been increased, respectively, by $68,000 ($0.11 per Bbl) and $202,000 ($0.02
per Mcf) for hedging gains during 2001. See Notes 11 and 15 to the
Consolidated Financial Statements of the Company included elsewhere in this
report for additional financial information regarding the Company's foreign
and domestic operations.

<TABLE>
<CAPTION>
                                                        Year Ended December 31,
                                                        -----------------------
                                                         2001    2000    1999
                                                        ------- ------- -------
   <S>                                                  <C>     <C>     <C>
   Net oil produced (MBbls):
     United States.....................................     396     294     324
     Canada............................................     203     110     138
                                                        ------- ------- -------
       Total...........................................     599     404     462
   Average oil sales price (per Bbl):
     United States..................................... $ 23.61 $ 26.38 $ 17.33
     Canada............................................   20.85   25.49   16.48
     Weighted average..................................   22.67   26.14   17.08
   Net gas product (MMcf):
     United States.....................................   4,498   3,850   4,421
     Canada............................................   5,376   4,519   4,660
                                                        ------- ------- -------
       Total...........................................   9,874   8,369   9,081
   Average gas sales price (per Mcf):
     United States..................................... $  3.47 $  4.08 $  2.24
     Canada............................................    3.51    3.54    1.58
     Weighted average..................................    3.49    3.79    1.90
   Gas equivalents produced (MMcfe):
     United States.....................................   6,874   5,614   6,365
     Canada............................................   6,594   5,179   5,488
                                                        ------- ------- -------
       Total...........................................  13,468  10,793  11,853
   Average sales price (per Mcfe):
     United States..................................... $  3.63 $  4.18 $  2.44
     Canada............................................    3.51    3.63    1.76
     Weighted average..................................    3.57    3.92    2.13
   Production costs (per Mcfe):
     United States..................................... $  1.27 $  1.04 $  0.72
     Canada............................................    0.65    0.43    0.40
     Weighted average..................................    0.97    0.74    0.57
</TABLE>

                                       2
<PAGE>

Marketing

   PetroCorp's United States gas production is sold to a variety of pipelines,
marketing companies and utility end users at prices based on the spot market.
This gas is typically sold under short-term contracts ranging in length from
one month to one year. In Canada during 2001, nearly one-half of the Company's
gas was dedicated under long-term contracts to Pan-Alberta Gas Ltd. (Pan-
Alberta), a major Canadian gas aggregator and marketer. Under these contracts,
approximately 75% of the gas was resold into the United States, predominantly
to markets in the upper Midwest region. PetroCorp received a price, per Mcf,
from Pan-Alberta equal to Pan-Alberta's resale price less certain costs. Most
of the Company's remaining Canadian gas was sold to Engage Energy at spot
prices on either a daily or a monthly basis, except for a small portion sold
at fixed prices over a five-month period.

   PetroCorp's domestic crude oil and condensate production is sold to a
variety of purchasers typically on a monthly contract basis at posted field
prices or NYMEX prices, as determined by major buyers. In particular areas,
where production volumes are significant or the location is desirable for a
particular purchaser, or both, the Company has successfully negotiated bonuses
over the purchaser's general field postings for its production.

   During the year ended December 31, 2001, Engage Energy and Pan-Alberta
accounted for 32% and 22% of the Company's total sales, respectively. The
Company does not believe the loss of any purchaser would have a material
adverse effect on its financial position since the Company believes
alternative sales arrangements could be made on relatively comparable terms.

   In general, prices of oil and gas are dependent on numerous factors beyond
the control of the Company, such as competition, international events and
circumstances (including actions taken by the Organization of Petroleum
Exporting Countries (OPEC)), and certain economic, political and regulatory
developments. Since demand for natural gas is generally highest during winter
months, prices received for the Company's natural gas are subject to seasonal
variations.

Competition

   The oil and gas industry is highly competitive. The Company competes in
acquisitions and in the exploration, development, production and marketing of
oil and gas with major oil companies, larger independent oil and gas concerns
and individual producers and operators. Many of these competitors have
substantially greater financial and other resources than the Company.

Regulation

 United States

   General. The Company's business is affected by numerous governmental laws
and regulations, including energy, environmental, conservation and tax laws.
For example, state and federal agencies have issued rules and regulations that
require permits for the drilling of wells, regulate the spacing of wells,
prevent the waste of reserves through proration, and regulate oilfield and
pipeline environmental and safety matters. Changes in any of these laws could
have a material adverse effect on the Company's business, and the Company
cannot predict the overall effects of such laws and regulations on its future
operations. Although these regulations have an impact on the Company and
others in the oil and gas industry, the Company does not believe that it is
affected in a significantly different manner by these regulations than are its
competitors in the oil and gas industry.

   The following discussion contains summaries of certain laws and regulations
and is qualified in its entirety by the foregoing.

   Regulation of Transportation and Sale of Natural Gas and Oil. Various
aspects of the Company's oil and gas operations are regulated by agencies of
the federal government. The transportation of natural gas in interstate
commerce is generally regulated by the Federal Energy Regulatory Commission
(FERC) pursuant to the Natural Gas Act of 1938 (the NGA) and the Natural Gas
Policy Act of 1978 (NGPA). The intrastate transportation and

                                       3
<PAGE>

gathering of natural gas (and operational and safety matters related thereto)
may be subject to regulation by state and local governments.

   In the past, the federal government regulated the prices at which the
Company's produced oil and gas could be sold. Currently, "first sales" of
natural gas by producers and marketers, and all sales of crude oil, condensate
and natural gas liquids, can be made at uncontrolled market prices, but
Congress could reenact price controls at any time.

   Within the past decade, the FERC has issued numerous orders and policy
statements designed to create a more competitive environment in the national
natural gas marketplace, including orders promoting "open-access"
transportation on natural gas pipelines subject to the FERC's NGA and NGPA
jurisdiction. The FERC's "Order 636" was issued in April 1992 and was designed
to restructure the interstate natural gas transportation and marketing system
and to promote competition within all phases of the natural gas industry.
Among other things, Order 636 required interstate pipelines to separate the
transportation of gas from the sale of gas, to change the manner in which
pipeline rates were designed and to implement other changes intended to
promote the growth of market centers. Subsequent FERC initiatives have
attempted to standardize interstate pipeline business practices and to allow
pipelines to implement market-based, negotiated and incentive rates. The
restructured services implemented by Order 636 and successor orders have now
been in effect for a number of winter heating seasons and have significantly
affected the manner in which natural gas (both domestic and foreign) is
transported and sold to consumers.

   Order 636 has generally been upheld in judicial appeals to date. However,
FERC routinely evaluates whether its approach to regulation of the natural gas
industry should be changed and whether further refinements or changes to
existing policies should be made in view of developments in the natural gas
industry since Order 636 was originally issued. Although FERC has indicated
that it remains committed to Order 636's "fundamental goal" of "improving the
competitive structure of the natural gas industry in order to maximize the
benefits of wellhead decontrol," the future regulatory goals and priorities of
FERC may change, and it is not possible to predict the effect, if any, of
future restructuring orders or policies on the Company's operations. FERC's
policies may also be impacted by the ongoing restructuring of the electric
power industry pursuant to FERC Order No. 888.

   While Order 636 and related orders do not directly regulate either the
production or sale of gas that may be produced from the Company's properties,
the increased competition and changes in business practices within the natural
gas industry resulting from such orders have affected the terms and conditions
under which the Company markets and transports its available gas supplies. To
date, the FERC's pro-competition policies have not materially affected the
Company's business or operations. On a prospective basis, however, such orders
may substantially increase the burden on producers and transporters to
accurately nominate and deliver on a daily basis specified volumes of natural
gas, or to bear penalties or increased costs in the event scheduled deliveries
are not made.

   Environmental Regulation. Various federal, state and local laws and
regulations governing the discharge of materials into the environment, or
otherwise relating to the protection of the environment, may affect the
Company's operations and costs. In particular, the Company's exploration,
exploitation and production operations, its activities in connection with
storage and transportation of crude oil and other liquid hydrocarbons and its
use of facilities for treating, processing or otherwise handling hydrocarbons
and wastes therefrom are subject to stringent environmental regulation.
Although compliance with these regulations increases the cost of Company
operations, such compliance has not in the past had a material effect on the
Company's capital expenditures, earnings or competitive position.
Environmental regulations have historically been subject to frequent change by
regulatory authorities. The trend toward stricter standards in environmental
legislation and regulation is likely to continue. For instance, legislation
has been proposed in Congress from time to time that would reclassify certain
oil and gas exploration and production wastes as "hazardous wastes," which
would make the reclassified wastes subject to much more stringent handling,
disposal and cleanup requirements. If such legislation were to be enacted, it
could have a significant impact on the operating costs of the Company, as well

                                       4
<PAGE>

as the oil and gas industry in general. Also at the federal level, the U.S. Oil
Pollution Act requires owners and operators of facilities that could be the
source of an oil spill into "waters of the United States" (a term defined to
include rivers, creeks, wetlands and coastal waters) to demonstrate that they
have at least $35 million in financial resources to pay for the costs of
cleaning up an oil spill and compensating any parties damaged by an oil spill.
Such financial assurances may be increased to as much as $150 million if a
formal assessment indicates such an increase is warranted. These financial
responsibility requirements could have a significant adverse impact on small
oil and gas companies like PetroCorp. State initiatives to further regulate the
disposal of oil and gas wastes are also pending in certain states, and these
various initiatives could have a similar impact on the Company. The Company is
unable to predict the ongoing cost to it of complying with these laws and
regulations or the future impact of such regulations on its operation.
Management believes that the Company 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. A catastrophic discharge of hydrocarbons into the environment could,
to the extent such event is not insured, subject the Company to substantial
expense.

 Canada

   In Canada, the petroleum industry operates under federal, provincial and
municipal legislation and regulations governing taxes, land tenure, royalties,
production rates, environmental protection, exports and other matters. Prices
of oil and natural gas in Canada have been deregulated and are determined by
market conditions and negotiations between buyers and sellers, although oil
production volumes are regulated. Various matters relating to the
transportation and distribution of natural gas are the subject of hearings
before various regulatory tribunals. In addition, although the price of natural
gas exported from Canada is subject to negotiation between buyers and sellers,
the National Energy Board, which regulates exports of natural gas, requires
that natural gas export contracts meet certain criteria as a condition of
approving such contracts. These criteria, including price considerations, are
designed to demonstrate that the export is in the Canadian public interest.
Several provincial governments have introduced a number of programs to
encourage and assist the oil and natural gas industry, including incentive
payments, royalty holidays and royalty tax credits. Canadian governmental
regulations may have a material effect on the economic parameters for engaging
in oil and gas activities in Canada and may have a material effect on the
advisability of investments in Canadian oil and gas drilling activities.

Employees

   At December 31, 2001, PetroCorp had no full-time employees. On January 1,
2002, Gary R. Christopher, President, and Richard L. Dunham, Executive Vice-
President, became direct employees of PetroCorp. Previously they had been
employees through the management agreement with Kaiser-Francis.

                                       5
<PAGE>

Item 2. Properties.

Principal Properties

   The Company's proved oil and gas properties are relatively concentrated.
Approximately 82% of the PV-10 from the Company's proved reserves at December
31, 2001 was attributable to four principal areas.

   The following table presents data regarding the estimated quantities of
proved oil and gas reserves and the PV-10 attributable to the Company's
principal properties as of December 31, 2001, in accordance with the rules and
regulations of the Securities and Exchange Commission (SEC).

<TABLE>
<CAPTION>
                                                     December 31, 2001
                                           -------------------------------------
                                              Estimated Proved
                                                  Reserves
                                           ----------------------
                                             Oil    Gas
                Property/Area              (MBbls) (MMcf)  MMcfe      PV-10
                -------------              ------- ------ ------- --------------
                                                                  (in thousands)
   <S>                                     <C>     <C>    <C>     <C>
   Hanlan-Robb (Canada)...................     39  34,462  34,696    $ 36,539
   Other Alberta (Canada).................  2,376  24,129  38,385      34,552
   Gulf Coast Area........................  1,306  10,298  18,134      21,712
   Mid-Continent Area.....................  1,365  13,186  21,376      16,750
                                            -----  ------ -------    --------
     Subtotal.............................  5,086  82,075 112,591     109,553
                                            -----  ------ -------    --------
   Others.................................  1,363  17,900  26,078      23,683
                                            -----  ------ -------    --------
     Total................................  6,449  99,975 138,669    $133,236
                                            =====  ====== =======    ========
</TABLE>

   Hanlan-Robb. PetroCorp's largest single producing area is the Hanlan-Robb
natural gas production complex located in the foothills region of western
Alberta, Canada. The Company owns interests in eleven producing fields in this
area, covering 46,000 developed acres. PetroCorp has additional interests in
80,000 undeveloped acres in this area. The key field is the Hanlan Swan Hills
Gas Unit #1, with current gross production of 130 MMcf/D. PetroCorp's
ownership is part of a joint venture managed by the Company with institutional
investors that collectively own 21.7% of the field. PetroCorp's working
interest in this field is 35% of the joint venture, or 7.6%. Petro-Canada (not
an affiliate of PetroCorp) is the largest interest owner in the area and
operates the Hanlan-Robb area fields and the related gathering system and
processing plant. Other significant PetroCorp fields in this area include
Shaw/Basing, Minehead, Columbia, Red Cap, Lambert, Banshee and Medicine Lodge.

   Other Alberta fields. PetroCorp, through existing interests and through the
2001 merger with Southern Mineral, has significant production in other core
areas throughout Alberta. This includes gas reserves in Pine Creek, Kaybob
South, McLeod and a Basal Colorado discovery in Alderson. Oil areas include
recent developments in Gift, along with Worsley and Hayter. In addition,
PetroCorp maintains minority ownership in large units, including Ghost Pine,
Mitsue and Pembina.

   Mid-Continent Area. Includes the Southwest Oklahoma City Field located
within the metropolitan Oklahoma City area. PetroCorp operates 63 wells in a
waterflood unit targeting the Prue formation at 6,500 feet. Current unit
production is approximately 340 BOPD. The Company owns an 86.4% working
interest in the unit. The Company also owns a 4% working interest in the
adjacent Will Rogers Unit, operated by Marathon.

   Other significant Mid-Continent properties include the Glick gas field in
south-central Kansas, the West Hunter Misener waterflood in Alfalfa County,
Oklahoma, and deep gas from the Cement field of Caddo County, Oklahoma.

   Gulf Coast Area. Includes ownership in the East Riceville Field in
Vermillion Parish, Louisiana and the Scott Field in Lafayette Parish,
Louisiana. East Riceville is a two-well gas field producing 16 MMcf/D from a
Miogyp reservoir at approximately 17,000 feet. PetroCorp owns a 13.8% working
interest in this field, which is operated by Murphy Exploration and Production
Company. Through the Southern Mineral merger, PetroCorp

                                       6
<PAGE>

now has significant interest in the Exxon operated Big Escambia Creek field in
Alabama. PetroCorp also drilled a successful sidetrack in the Maynor Creek
field of Wayne County, Mississippi.

Title to Properties

   United States. Except for the Company-owned mineral fee, royalty and
overriding royalty interests shown in the "Acreage and Wells" table below,
substantially all of the Company's United States property interests are held
pursuant to leases from third parties. The Company believes that it has
satisfactory title to its properties in accordance with standards generally
accepted in the oil and gas industry. In numerous instances, the Company has
acquired legal title to producing properties and has carved out of the
properties so acquired net profits royalty interests in favor of institutional
investors who supplied a substantial portion of the funds for the acquisition
of such properties. The producing property reserves of the Company are stated
after giving effect to the reduction in cash flow attributable to such net
profits royalty interests. In addition, the Company's properties are subject
to customary royalty interests, liens for current taxes and other burdens that
the Company believes do not materially interfere with the use of or affect the
value of such properties.

   Canada. Canadian property interests are held primarily under leases from
the Crown. A small percentage are from freehold owners. Prior to drilling on a
non-Crown lease or acquiring a non-Crown producing lease, the Company
generally obtains a title opinion covering the "historical" (freehold) title.
The Company generally relies on a title certificate under Canada's Torrens
title registration system to verify "current" (leasehold) ownership. Except
for these differences, title matters in Canada are similar to those in the
United States.

Oil and Gas Reserves

   All information herein regarding estimates of the Company's proved
reserves, related future net revenues and PV-10 is taken from reports prepared
by PetroCorp and reviewed by Huddleston & Co., Inc. (the Independent
Engineers). These reports were prepared in accordance with the rules and
regulations of the SEC and estimates of reserves were based upon production
histories and other geologic, economic, ownership and engineering data.

   The following table sets forth summary information with respect to the
estimates of the Company's proved oil and gas reserves as of December 31,
2001. The PV-10 values shown in the table are not intended to represent the
current market value of the estimated oil and gas reserves owned by the
Company. The average prices used in determining future cash inflows for
natural gas and oil as of December 31, 2001, were $2.48 per Mcf and $19.79 per
barrel, respectively. These prices were based on the adjusted cash spot price
for natural gas and oil at December 31, 2001.

<TABLE>
<CAPTION>
                                                          December 31, 2001
                                                      -------------------------
                                                      United
                                                      States   Canada   Total
                                                      ------- -------- --------
   <S>                                                <C>     <C>      <C>
   Proved reserves:
     Oil (MBbls).....................................   3,931    2,518    6,449
     Gas (MMcf)......................................  41,384   58,591   99,975
     Gas equivalents (MMcfe).........................  64,970   73,699  138,669
   Future net revenues ($000s)....................... $99,407 $122,894 $222,301
   Present value of future net revenues ($000s)...... $59,571 $ 73,665 $133,236

   Proved developed reserves:
     Oil (MBbls).....................................   3,350    2,242    5,592
     Gas (MMcf)......................................  38,806   50,876   89,682
     Gas equivalents (MMcfe).........................  58,906   64,328  123,234
   Future net revenues ($000s)....................... $93,664 $110,893 $204,557
   Present value of future net revenues ($000s)...... $57,881 $ 65,419 $123,300
</TABLE>

                                       7
<PAGE>

   There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and future
amounts and timing of development expenditures, including many factors beyond
the control of the Company. Reserve engineering is a subjective process of
estimating underground accumulations of crude 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. Estimates of proved undeveloped reserves are
inherently less certain than estimates of proved developed reserves. The
quantities of oil and gas that are ultimately recovered, production and
operating costs, the amount and timing of future development expenditures,
geologic success and future oil and gas sales prices may all differ from those
assumed in these estimates. In addition, the Company's reserves may be subject
to downward or upward revision based upon production history, purchases or
sales of properties, results of future development, prevailing oil and gas
prices and other factors. Therefore, the present value shown above should not
be construed as the current market value of the estimated oil and gas reserves
attributable to the Company's properties.

   In accordance with SEC guidelines, estimates of future net revenues from
the Company's proved reserves and the present value thereof are made using oil
and gas sales prices in effect as of the dates of such estimates and are held
constant throughout the life of the properties except where such guidelines
permit alternate treatment, including, in the case of gas contracts, the use
of fixed and determinable contractual price escalations. See "Marketing" under
Item 1 of this report, "Management's Discussion and Analysis of Financial
Condition and Results of Operations" under Item 7 of this report and Note 15
to the Consolidated Financial Statements of the Company. Estimates of the
Company's proved oil and gas reserves were not filed with or included in
reports to any other federal authority or agency other than the SEC during the
fiscal year ended December 31, 2001.

Acreage and Wells

   The following table sets forth certain information with respect to the
Company's developed and undeveloped leased acreage as of December 31, 2001.

<TABLE>
<CAPTION>
                                                     Developed     Undeveloped
                                                       Acres         Acres(1)
                                                   -------------- --------------
                                                    Gross   Net    Gross   Net
                                                   ------- ------ ------- ------
   <S>                                             <C>     <C>    <C>     <C>
   United States:
     Alabama......................................   9,619  2,336      --     --
     Colorado.....................................  10,186  7,958      --     --
     Kansas.......................................   5,360    667      10      1
     Louisiana....................................  14,339  2,717     883    193
     Mississippi..................................   2,880    487   8,430  6,049
     Oklahoma.....................................  39,969  9,950  11,325  4,325
     Texas........................................  49,353 12,031  42,211 11,334
     Wyoming......................................   5,655    774   5,109    480
     Other........................................     800    204  22,679  4,841
   Canada:
     Alberta...................................... 157,456 14,843 182,222 37,306
     Other........................................  12,425  2,824  16,737  5,990
                                                   ------- ------ ------- ------
       Total...................................... 308,042 54,791 289,606 70,519
                                                   ======= ====== ======= ======
</TABLE>
--------
(1) Approximately 10% of net undeveloped acres are covered by leases that
    expire during 2002, unless drilling or production otherwise extends lease
    terms.

   As of December 31, 2001, the Company had working interests in 1389 gross
(175 net) producing oil wells and 590 gross (53 net) producing gas wells. Of
these wells, 1126 gross (67 net) oil wells and 404 gross (19 net) gas wells
were in Canada, and the remainder of the oil and gas wells were in the United
States.

                                       8
<PAGE>

Drilling Activities

   All of PetroCorp's drilling activities are conducted through arrangements
with independent contractors, and it owns no drilling equipment. Certain
information with regard to the Company's drilling activities completed during
the years ended December 31, 2001, 2000 and 1999 is set forth below:

<TABLE>
<CAPTION>
                                         Year Ended December 31,
                               -----------------------------------------------
                                    2001           2000              1999
                               -------------- --------------    --------------
                                       Net            Net               Net
                                     Working        Working           Working
          Type of Well         Gross Interest Gross Interest    Gross Interest
          ------------         ----- -------- ----- --------    ----- --------
   <S>                         <C>   <C>      <C>   <C>         <C>   <C>
   United States
    Development:
     Oil......................    3     .1       4     .2          4     .2
     Gas......................    8    1.0       5     .3          1     .0(/1/)
     Nonproductive............    3     .2       1     .2          1     .2
                                ---    ---     ---    ---        ---    ---
       Total..................   14    1.3      10     .7          6     .4
                                ---    ---     ---    ---        ---    ---
    Exploratory:
     Oil......................    1     .1      --     --         --     --
     Gas......................    3     .5      --     --         --     --
     Nonproductive............    2     .2       1     .0(/1/)     1     .2
                                ---    ---     ---    ---        ---    ---
       Total..................    6     .8       1     .0          1     .2
                                ---    ---     ---    ---        ---    ---
   Canada:
    Development:
     Oil......................   21     .8       1    1.0          1    1.0
     Gas......................    5     .9       6    1.1          2     .2
     Nonproductive............   --     --      --     --          2     .0(/1/)
                                ---    ---     ---    ---        ---    ---
       Total..................   26    1.7       7    2.1          5    1.2
                                ---    ---     ---    ---        ---    ---
    Exploratory:
     Oil......................    1     .6      --     --         --     --
     Gas......................    2     .4       3     .4          4     .2
     Nonproductive............   --     --      --     --          3     .1
                                ---    ---     ---    ---        ---    ---
       Total..................    3    1.0       3     .4          7     .3
                                ---    ---     ---    ---        ---    ---
   Total......................   49    4.8      21    3.2         19    2.1
                                ===    ===     ===    ===        ===    ===
</TABLE>
--------
(/1/The)Company has a net working interest less than 0.05% in these wells.

   At December 31, 2001, the Company was not participating in the drilling of
any wells in either Canada or the United States.

Hanlan-Robb Natural Gas Processing Plant and Gas Gathering Systems

   PetroCorp owns interests in a centrally located gas processing plant and in
a gas gathering system that connects all of the Company's currently producing
Hanlan-Robb fields to the Hanlan-Robb plant. Commissioned in 1983, the
estimated replacement value is approximately $175 ($C277) million. The
original design capacity of 300 MMcf/D has been expanded to 380 MMcf/D. Third-
party gas, for which processing fees are received, plus gas from additional
drilling in the area, has increased plant throughput to near capacity.
PetroCorp owns a 24.5% working interest in the plant and varying working
interests in the gathering systems, dehydration and compression facilities
that deliver gas to the plant.

                                       9
<PAGE>

Other Facilities

   The Company leases, and subleases to others, approximately 10,000 square
feet in Houston, Texas where the Southern Mineral offices were located and
approximately 4,000 square feet in Calgary, Alberta where divisional offices
were previously located. The obligation under these leases will end in 2003
for the Houston lease and 2002 for the Calgary lease. Additionally, the
Company owns an 18,400 square-foot building and surface pads covering
approximately 42 acres related to its Southwest Oklahoma City Field operations
and a small gathering system in the Paradox Basin area of southwestern
Colorado.

                  FORWARD-LOOKING STATEMENTS AND RISK FACTORS

   Current and prospective stockholders should carefully consider the
following risk factors in evaluating an investment in PetroCorp. The
information discussed herein includes "forward-looking statements" within the
meaning of Section 27A of the Securities Act of 1933, as amended (the
"Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as
amended (the "Exchange Act"). All statements other than statements of
historical facts included herein regarding planned capital expenditures,
increases in oil and gas production, the number of anticipated wells to be
drilled after the date hereof, the Company's financial position, business
strategy and other plans and objectives for future operations, are forward-
looking statements. Although the Company believes that the expectations
reflected in such forward-looking statements are reasonable, they do involve
certain assumptions, risks and uncertainties, and the Company can give no
assurance that such expectations will prove to have been correct. The
Company's actual results could differ materially from those anticipated in
these forward-looking statements as a result of certain factors, including
those set forth in the following risk factors.

   All subsequent written and oral forward-looking statements attributable to
the Company or persons acting on its behalf are expressly qualified in their
entirety by such factors.

Volatile Nature of Oil and Gas Markets; Fluctuations in Prices

   The Company's future financial condition and results of operations are
highly dependent on the demand and prices received for oil and gas production
and on the costs of acquiring, developing and producing reserves. Oil and gas
prices have historically been volatile and are expected by the Company to
continue to be volatile in the future. Prices for oil and gas are subject to
wide fluctuation in response to relatively minor changes in the supply of and
demand for oil and gas, market uncertainty and a variety of additional factors
that are beyond the Company's control. These factors include political
conditions in the Middle East and elsewhere, domestic and foreign supply of
oil and gas, the level of consumer demand, weather conditions, domestic and
foreign government regulations and taxes, the price and availability of
alternative fuels and overall economic conditions. A decline in oil or gas
prices may adversely affect the Company's cash flow, liquidity and
profitability and may result in "ceiling test" write downs of the oil and gas
properties. Lower oil or gas prices also may reduce the amount of the
Company's oil and gas that can be produced economically.

Dependence on Acquiring and Finding Additional Reserves

   The Company's prospects for future growth and profitability will depend
predominantly on its ability to replace present reserves through acquisitions
and exploratory drilling, as well as on its ability to successfully develop
additional reserves. There can be no assurance that the Company's acquisition
and exploration activities or planned development projects will result in
significant additional reserves or that the Company will have continuing
success at drilling economically productive wells.

Substantial Capital Requirements

   The Company has made substantial capital expenditures in connection with
the acquisition, exploration and development of oil and gas properties. Future
cash flows and the availability of credit are subject to a number of

                                      10
<PAGE>

variables, such as the level of production from existing wells, prices of oil
and gas and the Company's success in locating and producing new reserves. If
revenues were to decrease as a result of lower oil and gas prices, decreased
production or otherwise, and the Company had no available credit, the Company
could be limited in its ability to replace its reserves or to maintain
production at current levels, resulting in a decrease in production and revenue
over time. If the Company's cash flow from operations and available credit are
not sufficient to satisfy its capital expenditure requirements, there can be no
assurance that additional debt or equity financing will be available to meet
these requirements.

Reliance on Estimates of Reserves and Future Net Cash Flows

   There are numerous uncertainties inherent in estimating quantities of proved
oil and gas reserves, including many factors beyond the Company's control.
Petroleum engineering is a subjective process of estimating underground
accumulations of oil and gas that cannot be measured in an exact manner.
Estimates of economically recoverable oil and gas reserves and of future net
cash flow necessarily depend upon a number of variable factors and assumptions,
such as historical production from the area compared with production from other
producing areas, the assumed effects of regulation by governmental agencies,
assumptions concerning future oil and gas prices, future operating costs,
severance and excise taxes, development costs and workover and remedial costs,
all of which may in fact vary considerably from actual results. For these
reasons, estimates of the economically recoverable quantities of oil and gas
attributable to any particular group of properties, classifications of such
reserves based on risk of recovery and estimates of the future net cash flows
expected therefrom prepared by different engineers or by the same engineers at
different times may vary significantly. Actual production, revenues and
expenditures with respect to the Company's reserves likely will vary from
estimates, and such variances may be material. In addition, the Company's
reserves and future cash flows may be subject to revisions based upon
production history, results of future development, oil and gas prices,
performance of counterparties under agreements to which the Company is a party,
operating and development costs and other factors.

   The PV-10 values referred to herein should not be construed as the current
market value of the estimated oil and gas reserves attributable to the
Company's properties. In accordance with applicable requirements of the SEC,
the PV-10 values are generally based on prices and costs as of the date of the
estimate, whereas actual future prices and costs may be materially higher or
lower. Actual future net cash flows also will be affected by factors such as
the amount and timing of actual production, supply and demand for oil and gas,
curtailments or increases in consumption by natural gas purchasers and changes
in governmental regulations or taxation. The timing of actual future net cash
flows from proved reserves, and thus their actual present value, will be
affected by the timing of both the production and the incurrence of expenses in
connection with development and production of oil and gas properties. In
addition, the 10% discount factor (which is required by the SEC to be used to
calculate PV-10 for reporting purposes), is not necessarily the most
appropriate discount factor based on interest rates in effect from time to time
and risks associated with the Company and its properties or the oil and gas
industry in general.

Exploration Risks

   Exploratory drilling activities are subject to many risks, including the
risk that no commercially productive reservoirs will be encountered, and there
can be no assurance that new wells drilled by the Company will be productive or
that the Company will recover all or any portion of its investment. Drilling
for oil and gas may involve unprofitable efforts, not only from non-productive
wells, but from wells that are productive but do not produce sufficient net
revenues to return a profit after drilling, operating and other costs. The cost
of drilling, completing and operating wells is often uncertain. The Company's
drilling operations may be curtailed, delayed or canceled as a result of
numerous factors, many of which are beyond the Company's control, including
title problems, weather conditions, compliance with governmental requirements
and shortages or delays in the delivery of equipment and services.

                                       11
<PAGE>

Marketing Risks

   The Company's ability to market its oil and gas production at commercially
acceptable prices is dependent on, among other factors, the availability and
capacity of gathering systems and pipelines, federal and state regulation of
production and transportation, general economic conditions, and changes in
supply and in demand.

Acquisition Risks

   Acquisitions of oil and gas businesses and properties have been an
important element of the Company's success, and the Company will continue to
seek acquisitions in the future. Even though the Company performs a review
(including a limited review of title and other records) of the major
properties it seeks to acquire that it believes is consistent with industry
practices, such reviews are inherently incomplete and it is generally not
feasible for the Company to review in-depth every property and all records.
Even an in-depth review may not reveal existing or potential problems or
permit the Company to become familiar enough with the properties to assess
fully their deficiencies and capabilities, and the Company often assumes
environmental and other liabilities in connection with acquired businesses and
properties.

Operating Risks

   The Company's operations are subject to numerous risks inherent in the oil
and gas industry, including the risks of fire, explosions, blow-outs, pipe
failure, abnormally pressured formations and environmental accidents such as
oil spills, natural gas leaks, ruptures or 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,
clean-up responsibilities, regulatory investigation and penalties and
suspension of operations. The Company's operations may be materially
curtailed, delayed or canceled as a result of numerous factors, including the
presence of unanticipated pressure or irregularities in formations, accidents,
title problems, weather conditions, compliance with governmental requirements
and shortages or delays in the delivery of equipment. In accordance with
customary industry practice, the Company maintains insurance against some, but
not all, of the risks described above. There can be no assurance that the
levels of insurance maintained by the Company will be adequate to cover any
losses or liabilities.

Competitive Industry

   The oil and gas industry is highly competitive. The Company competes for
corporate and property acquisitions and the exploration, development,
production, transportation and marketing of oil and gas, as well as
contracting for equipment and securing personnel, with major oil and gas
companies, other independent oil and gas concerns and individual producers and
operators. Many of these competitors have financial and other resources which
substantially exceed those available to the Company.

Risks That Might Arise from the Management Agreement

   The Company has only two employees, and all of its technical and corporate
services are provided by Kaiser-Francis pursuant to a management agreement. As
a result, the Company does not have full control over its operations. Either
the Company or Kaiser-Francis may terminate the Kaiser-Francis management
agreement at any time upon six month's notice. If the agreement is terminated,
and if the Company is unable to engage third parties to perform these services
and have to replicate facilities, services or employees that the Company is
not using full time, or are not able to engage a third party at costs similar
to those charged by Kaiser-Francis, the Company's costs would increase. The
Company may not be able to find another contractor to provide substantially
similar services at the same rates or replicate such services without
incurring additional costs.

   Kaiser Francis, PetroCorp's largest shareholder, and its subsidiaries
explore for and produce oil and gas in some of the same geographic areas in
which the Company operates. Kaiser-Francis is not required to pursue a

                                      12
<PAGE>

business strategy that will favor PetroCorp business opportunities over the
business opportunities of Kaiser-Francis, its affiliates, or any other
competitor of Petrocorp acquired by Kaiser-Francis. In fact, Kaiser-Francis may
have financial motives to favor itself.

   In addition, because of the Company's management agreement with Kaiser-
Francis, PetroCorp, Kaiser-Francis and its affiliates share, and therefore will
compete for, the time and effort of Kaiser-Francis personnel who provide
services to the Company. Officers of Kaiser-Francis and its affiliates do not
and will not be required to spend any specified percentage or amount of their
time on the Company's business. Since these shared officers function as both
the Company's representatives and those of Kaiser-Francis and its affiliates,
conflicts of interest could arise between Kaiser-Francis and its affiliates, on
the one hand, and the Company and its shareholders, on the other.

Government Regulation

   The Company's business is subject to certain federal, state and local laws
and regulations relating to the drilling for and production, transportation and
marketing of oil and gas, as well as environmental and safety matters. Such
laws and regulations have generally become more stringent in recent years,
often imposing greater liability on an increasing number of parties and in some
circumstances creating retroactive liability. Because the requirements imposed
by such laws and regulations are frequently changed, the Company is unable to
predict the effect or cost of compliance with such requirements or their
effects on oil and gas use or prices. In addition, legislative proposals are
frequently introduced in Congress and state legislatures which, if enacted,
might significantly affect the oil and gas industry. In view of the many
uncertainties which exist with respect to any legislative proposals, the effect
on the Company of any legislation which might be enacted cannot be predicted.

Hedging Activities

   The Company utilizes energy swap arrangements and financial futures to
reduce sensitivity to oil and gas price volatility. 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, the Company will be required to satisfy obligations it may have
under fixed price sales or hedging contracts on potentially unfavorable terms
without the ability to hedge that risk through sales of comparable quantities
of its own production. Further, the terms under which the Company enters into
fixed price sales and hedging contracts are based on assumptions and estimates
of numerous factors such as cost of production and pipeline and other
transportation costs to delivery points. Substantial variations between the
assumptions and estimates used and actual results experienced could materially
adversely affect anticipated profit margins and PetroCorp's ability to manage
the risk associated with fluctuations in oil and gas prices.

   In addition, fixed price sales and hedging contracts are subject to the risk
that the counter-party may prove unable or unwilling to perform its obligations
under these contracts. Any significant nonperformance could have a material
adverse financial effect on the Company.

Marketability of PetroCorp's Production

   The marketability of PetroCorp's production depends in part upon the
availability, proximity and capacity of oil and gas gathering systems,
pipelines and processing facilities. Most of the Company's oil and gas will be
delivered through gathering systems and pipelines that are not owned by the
Company. Federal and state regulation of oil and gas production and
transportation, tax and energy policies, changes in supply and demand and
general economic conditions all could adversely affect the Company's ability to
produce and market its oil and gas.

                                       13
<PAGE>

Item 3. Legal Proceedings.

   The Company is a party to various lawsuits and governmental proceedings, all
arising in the ordinary course of business. Although the outcome of these
lawsuits cannot be predicted with certainty, the Company does not expect such
matters to have a material adverse effect, either singly or in the aggregate,
on the financial position of the Company.

   On February 13, 2002, R.A. Mackie & Co., L.P., Millenco, L.P. and Wein
Securities Corp, as plaintiffs, filed a lawsuit against PetroCorp in New York
Supreme Court (Index No. 02-600589). In this action certain former holders of
warrants of Southern Mineral Corporation allege that the provisions made for
such warrants in connection with the merger of Southern Mineral Corporation
into PetroCorp Acquisition Corporation, a wholly-owned subsidiary of PetroCorp
Incorporated, were inadequate. The plaintiffs seek $5,000,000. Based on
consultation with outside legal counsel, the Company is of the opinion the
action is without merit.

Item 4. Submission of Matters to a Vote of Security Holders.

   None.

                                       14
<PAGE>

                                    PART II

Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.

   The Company's Common Stock is currently listed on the American Stock
Exchange (the "AMEX") and trades under the symbol PEX. The Company's Common
Stock has been listed with the AMEX since September 17, 1998. Prior to that
time, the Company's Common Stock had been listed on The Nasdaq Stock Market
since October 28, 1993. The following table presents the high and low closing
prices for the Company's Common Stock for each quarter during 2000 and 2001,
and for a portion of the Company's current quarter, as reported by the AMEX.

<TABLE>
<CAPTION>
                                      2000                            2001                   2002
                         ------------------------------- ------------------------------- ------------
                                                                                            First
                                                                                           Quarter
                          First  Second   Third  Fourth   First  Second   Third  Fourth    (through
                         Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter February 28)
                         ------- ------- ------- ------- ------- ------- ------- ------- ------------
<S>                      <C>     <C>     <C>     <C>     <C>     <C>     <C>     <C>     <C>
High....................  $6.75   $7.25   $9.88  $10.19  $10.63  $10.70   $9.88   $9.50     $9.50
Low.....................   5.25    5.50    7.00    8.63    9.62    9.37    8.60    8.70      8.70
</TABLE>

   As of February 28, 2002, the closing price for the Company's Common Stock
was $9.50 per share. As of February 28, 2002, there were approximately 2,500
holders of record of the Common Stock.

   The Company has not declared or paid any cash dividends on its Common Stock
to date. The Board of Directors of the Company does not intend to declare cash
dividends on its Common Stock in the foreseeable future. The Company intends
instead to retain its earnings to support the growth of the Company's
business. Any future cash dividends would depend on future earnings, capital
requirements, the Company's financial condition and other factors deemed
relevant by the Company's Board of Directors. The terms of the Company's
credit facility prohibits the declaration or payment of any dividends.

                                      15
<PAGE>

Item 6. Selected Financial Data.

   The following table summarizes consolidated financial data of the Company
and should be read in conjunction with the "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and the
Consolidated Financial Statements of the Company, including the Notes thereto,
included elsewhere in this report.

<TABLE>
<CAPTION>
                                   For the Year Ended December 31,
                             ------------------------------------------------
                               2001      2000      1999      1998      1997
                             --------  --------  --------  --------  --------
                               (In thousands, except per share amounts)
<S>                          <C>       <C>       <C>       <C>       <C>
Income Statement Data:
Revenues:
  Oil and gas............... $ 48,058  $ 42,264  $ 25,162  $ 23,621  $ 33,502
  Plant processing..........    1,817     1,934     1,785     1,550     1,420
  Other (B).................    1,399     1,278     1,079       936     1,072
                             --------  --------  --------  --------  --------
                               51,274    45,476    28,026    26,107    35,994
                             --------  --------  --------  --------  --------
Expenses:
  Production costs..........   12,997     8,038     6,733     7,344     7,793
  Depreciation, depletion
   and amortization.........   16,944     9,471     9,906    16,568    17,065
  Oil and gas property
   valuation adjustment.....   15,400        --        --    33,600        --
  General and
   administrative...........    2,259     1,529     4,311     4,482     4,846
  Restructuring costs.......       --     (445)     3,643        --        --
  Other operating expenses
   (B)......................    1,485     1,212     1,181     1,165     1,267
                             --------  --------  --------  --------  --------
                               49,085    19,805    25,774    63,159    30,971
                             --------  --------  --------  --------  --------
Income (loss) from
 operations.................    2,189    25,671     2,252  (37,052)     5,023
                             --------  --------  --------  --------  --------
Other income (expenses):
  Investment income.........      143       584       585     1,151       558
  Interest expense..........   (1,991)   (3,381)   (3,865)   (3,622)   (3,528)
  Other income (expenses)...    1,425       295      (132)       14       (47)
                             --------  --------  --------  --------  --------
                                 (423)   (2,502)   (3,412)   (2,457)   (3,017)
                             --------  --------  --------  --------  --------
Income (loss) before income
 taxes......................    1,766    23,169    (1,160)  (39,509)    2,006

Income tax provision
 (benefit);
  Current...................    5,552     5,497        --        --        --
  Deferred..................   (5,832)    4,612      (954)  (15,114)      136
                             --------  --------  --------  --------  --------
                                 (280)   10,109      (954)  (15,114)      136
                             --------  --------  --------  --------  --------

Net income (loss) before
 extraordinary item.........    2,046    13,060      (206)  (24,395)    1,870
Extraordinary loss -
 extinguishment of debt
 (less applicable tax
 benefit of $143)                  --       242        --        --        --
                             --------  --------  --------  --------  --------

Net income (loss)            $  2,046  $ 12,818  $   (206) $(24,395) $  1,870
                             --------  --------  --------  --------  --------

Net income (loss) per
 share--basic (A)........... $   0.19  $   1.47  $  (0.02) $  (2.82) $   0.22
                             ========  ========  ========  ========  ========
Net income (loss) per
 share--diluted (A)......... $   0.18  $   1.46  $  (0.02) $  (2.82) $   0.22
                             ========  ========  ========  ========  ========
Weighted average number of
 common shares--basic.......   10,975     8,692     8,658     8,637     8,586
                             ========  ========  ========  ========  ========
Weighted average number of
 common shares--diluted.....   11,119     8,786     8,658     8,637     8,688
                             ========  ========  ========  ========  ========
Balance Sheet Data (at
 December 31):
  Working Capital........... $  4,031  $  9,029  $  3,642  $  2,080  $  2,638
  Total assets..............  165,355   117,319   105,395   103,992   130,924
  Long-term debt............   47,620    29,992    43,410    47,305    42,192
  Shareholders' equity......   91,915    54,277    42,363    40,744    66,557
</TABLE>

--------
(A) Basic and diluted net income per share before extraordinary loss for the
    year ended December 31, 2000 were $1.50 and $1.49, respectively.
(B) As a result of the new accounting requirement to report transportation and
    gathering costs as revenues and costs, rather than reducing revenues for
    these costs, prior year revenues and costs have been increased by $903 in
    2000 and $900 in 1999 through 1997.

                                      16
<PAGE>

Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.

General

   The Company's principal line of business is the production and sale of its
oil and natural gas reserves located in North America. Results of operations
are dependent upon the quantity of production and the price obtained for such
production. Prices received by the Company for the sale of its oil and natural
gas have fluctuated significantly from period to period. Such fluctuations
affect the Company's ability to maintain or increase its production from
existing oil and gas properties and to explore, develop or acquire new
properties.

   The following table reflects certain operating data for the periods
presented:
<TABLE>
<CAPTION>
                                                             For the Year Ended
                                                                December 31,
                                                            --------------------
                                                             2001   2000   1999
                                                            ------ ------ ------
<S>                                                         <C>    <C>    <C>
Production:
 United States:
  Oil (MBbls)..............................................    396    294    324
  Gas (MMcf)...............................................  4,498  3,850  4,421
  Gas equivalents (MMcfe)..................................  6,874  5,614  6,365
 Canada:
  Oil (MBbls)..............................................    203    110    138
  Gas (MMcf)...............................................  5,376  4,519  4,660
  Gas equivalents (MMcfe)..................................  6,594  5,179  5,488
 Total:
  Oil (MBbls)..............................................    599    404    462
  Gas (MMcf)...............................................  9,874  8,369  9,081
  Gas equivalents (MMcfe).................................. 13,468 10,793 11,853

Average sales prices:
 United States:
  Oil (per Bbl)............................................ $23.61 $26.38 $17.33
  Gas (per Mcf)............................................   3.47   4.08   2.24
 Canada:
  Oil (per Bbl)............................................  20.85  25.49  16.48
  Gas (per Mcf)............................................   3.51   3.54   1.58
 Weighted average:
  Oil (per Bbl)............................................  22.67  26.14  17.08
  Gas (per Mcf)............................................   3.49   3.79   1.90

Selected data per Mcfe:
 Average sales price....................................... $ 3.57 $ 3.92 $ 2.13
 Production costs..........................................   0.97   0.74   0.57
 General and administrative expenses.......................   0.17   0.14   0.36
 Oil and gas depreciation, depletion and amortization......   1.15   0.74   0.69
</TABLE>

                                      17
<PAGE>

Critical Accounting Policies

   Oil and Gas Properties--The Company accounts for oil and natural gas
exploration and development activities using the full cost method of
accounting. Under this method, all costs incurred in the acquisition,
exploration and development of oil and natural gas properties are capitalized.
At the end of each quarter, the net unamortized capitalized cost of oil and
natural gas properties is compared to a "ceiling". The ceiling is defined as
the sum of the present value (10 percent discount rate) of estimated future
net revenues from proved reserves, based on period-ending oil and natural gas
prices, plus the lower of cost or estimated fair value of unproved properties
included in the costs being amortized, less related deferred income taxes. If
the net capitalized costs of oil and natural gas properties exceed the
ceiling, the Company is subject to a ceiling test write-down to the extent of
such excess. A ceiling test write-down, also described as a property valuation
adjustment, is a non-cash charge to earnings. If required, it reduces earnings
and impacts stockholders' equity in the period of occurrence and results in
lower depreciation, depletion and amortization expense in future periods. Once
written down, oil and gas properties can not be adjusted upward due to
subsequent increase in reserve values.

   The risk that PetroCorp will be required to write-down the carrying value
of oil and natural gas properties increases when oil and natural gas prices
are depressed or if there are substantial downward revisions in estimated
proved reserves. Application of these rules during periods of relatively low
oil or natural gas prices, even if temporary, increases the probability of a
ceiling test write-down. Based on oil and natural gas prices in effect on
December 31, 2001 of $19.84 per barrel and $2.70 per Mcf in the United States
and $19.73 per barrel and $2.32 per Mcf in Canada, the unamortized cost of
domestic oil and natural gas properties exceeded the ceiling of our proved oil
and natural gas reserves and a valuation adjustment of $15,400,000 was
recorded. Natural gas pricing has been fluctuating since year-end and any
significant declines below year-end prices used in the reserve evaluation may
result in an additional ceiling test write-down in subsequent quarters.

   The value of the Company's oil and natural gas reserves is used to
determine the loan value under the Company's loan agreement. This value is
affected by both price changes and the measurement of reserve volumes. Oil and
natural gas reserves cannot be measured exactly. PetroCorp's estimate of oil
and natural gas reserves require extensive judgments of our reservoir
engineering data and are generally less precise than other estimates made in
connection with financial disclosures. Assigning monetary values to such
estimates does not reduce the subjectivity and changing nature of such reserve
estimates. The uncertainties inherent in the disclosure are compounded by
applying additional estimates of the rates and timing of production and the
costs that will be incurred in developing and producing the reserves.
PetroCorp utilizes Huddleston & Co, Inc., independent petroleum consultants,
to review the Company's reserves as prepared by PetroCorp's reservoir
engineer.

   Income Taxes. As part of the process of preparing the consolidated
financial statements, PetroCorp is required to estimate the income taxes in
each of the jurisdictions in which PetroCorp operates. This process involves
estimating the actual current tax exposure together with assessing temporary
differences resulting from differing treatment of items, such as depreciation,
amortization and certain accrued liabilities, for tax and accounting purposes.
These differences and the net operating loss carryforwards result in deferred
tax assets and liabilities, which are included within PetroCorp's consolidated
balance sheet. PetroCorp must then assess the likelihood that the deferred tax
assets will be recovered from future taxable income and to the extent the
Company believes that recovery is not likely, PetroCorp must establish a
valuation allowance. To the extent PetroCorp establishes a valuation allowance
or increases or decreases this allowance in a period, the Company must include
an expense or reduction of expense within the tax provisions in the
consolidated statement of operations.

   Deferred income tax assets and liabilities are recorded whenever underlying
transactions result in temporary differences between financial accounting and
what will be included in the Company's tax returns. Permanent differences are
taken into account in determining the Company's effective tax rate. The intent
of recording deferred taxes is to cause the Company's financial income tax
expense to be consistent with the underlying tax rates. To the extent deferred
tax estimation doesn't correctly predict how transactions are later reflected
in tax returns, adjustments will be required.

                                      18
<PAGE>

   Examples of temporary differences include the tax expensing of intangible
drilling costs while such costs are capitalized as part of the full cost pool
for financial purposes. Another example is accelerated depreciation and
depletion for tax purposes compared to financial depreciation and depletion.
Both examples cause an excess basis in oil and gas properties for financial
purposes as compared to tax basis, which results in a deferred liability.

   PetroCorp's other significant temporary differences are the net operating
loss carryforwards (NOLs), which are tax losses available to offset future
taxable income of the Company. They result in deferred tax assets. NOLs are an
asset for the Company only to the extent it is likely PetroCorp will have
future taxable income to offset against the NOLs. Although PetroCorp can make
some tax elections to its benefit, a period of sustained lower than normal oil
and gas prices could result in the inability of the Company to utilize NOLs
before they expire, resulting in the recording of a valuation allowance or, if
they expire without being utilized, resulting in a write-off of the deferred
tax asset.

   The Company's significant accounting policies are described in Note 1 to
the Consolidated Financial Statements.

Restructuring

   As part of a restructuring plan, on August 3, 1999, PetroCorp's Board of
Directors entered into a Management Agreement with its largest shareholder,
Kaiser-Francis, under which Kaiser-Francis provides management, technical, and
administrative support services for all PetroCorp operations in the United
States and Canada.

   Under the terms of the Management Agreement, as amended, Kaiser-Francis is
compensated through a service fee equal to administrative and overhead fees
charged under applicable operating agreements plus fixed fees of no more than
$50 per well per month for non-operated properties. Fees and cost
reimbursements for 2001, 2000, and 1999 respectively, were $3,064,000,
$2,076,000 and $1,419,000 ($2,176,000, $1,419,000 and $218,000 for
administration fees).

   The Company recorded restructuring costs of $3,643,000 during 1999.
Included in the costs were employee termination costs of $2,371,000, $807,000
in nonrefundable office lease discontinuance, $363,000 in investment banking
and legal costs, and $102,000 in other related costs. As of December 31, 2000,
$70,000 of the remaining restructuring costs were included in accrued
liabilities.

   As a result of the restructuring, fifty-two employees were terminated in
1999 with one employee terminated in 2000. Several employees elected to defer
receipt of their termination benefits until 2000. The Houston, Oklahoma City
and Calgary offices were closed, but the Company was still liable under the
lease agreements. In the second quarter of 2000, the Company was able to find
a replacement lessee for some of the idle office space earlier than
anticipated. The following table shows the change in accrued restructuring
costs during 2001(in thousands):

<TABLE>
<CAPTION>
                                          Expenditures
                              Balance at    charged                Balance at
                             December 31,   against    Changes in December 31,
                                 2000       accrual    estimates      2001
                             ------------ ------------ ---------- ------------
<S>                          <C>          <C>          <C>        <C>
Office lease discontinuance
 and other related costs....      70           70          --          --
                                 ---          ---         ---         ---
                                 $70          $70         $--         $--
                                 ===          ===         ===         ===
</TABLE>


                                      19
<PAGE>

Results of Operations

 2001 Compared to 2000

   Overview. The Company recorded net income of $2,046,000 or $0.19 per share
in 2001, compared to net income of $12,818,000, or $1.47 per share, for the
corresponding period of 2000. This decrease results from lower oil and gas
prices, increased depreciation, depletion, and amortization expenses and an
oil and gas property valuation adjustment.

   Revenues. Total revenues increased 13% to $51.3 million in 2001 compared to
$45.5 million in 2000. Oil production increased 48% to 599 MBbls from 404
MBbls. Natural gas production increased 18% to 9,874 MMcf from 8,369 MMcf,
resulting in overall production increasing 25% to 13,468 MMcfe from 10,793
MMcfe. Production increases are primarily due to the merger with Southern
Mineral in June 2001.

   The Company's average U.S. natural gas price decreased 15% to $3.47 per Mcf
in 2001 from $4.08 per Mcf in 2000, while the average Canadian natural gas
price decreased less than 1% to $3.51 from $3.54. The Company's composite
average oil price decreased 13% to $22.67 per barrel in 2001 from $26.14 per
barrel in 2000. Primarily as a result of increased volumes due to the merger
with Southern Mineral, oil and gas revenues increased 14% to $48.1 million in
2001 from $42.3 million in 2000. Plant processing revenues decreased 5% to
$1.8 million from $1.9 million as a result of less third party processing in
the Canadian Hanlan-Robb gas processing plant.

   Production Costs. Production costs increased 63% to $13.0 million in 2001
compared to $8.0 million in 2000 as a result of the acquisition of Southern
Mineral and workover operations for repairs and production enhancements.
Production costs per Mcfe were $0.97 for 2001 and $0.74 for 2000.
Approximately $0.21 per Mcfe of increased costs are due to increased workover
operations.

   Depreciation, Depletion & Amortization (DD&A). Total DD&A increased 78% to
$16.9 million in 2001 from $9.5 million in 2000. The increase in the oil and
gas DD&A rate per Mcfe to $1.15 in 2001 from $0.74 in 2000 reflects the impact
of Southern Mineral properties added through the merger in June 2001 and the
lower year-end reserves amounts due to lower prices.

   Oil and Gas Property Valuation Adjustment. At December 31, 2001, as a
result of low oil and gas prices, the Company's net capitalized costs for its
U.S. oil and gas properties exceeded the ceiling, resulting in a non-cash
valuation adjustment of $15.4 million.

   General and Administrative Expenses. General and administrative expenses
increased 53% to $2.3 million in 2001 from $1.5 million in 2000 due to office
close down costs and higher management fees, both due to the impact of the
merger with Southern Mineral.

   Investment Income. Investment income decreased 76% to $143,000 in 2001 from
$584,000 in 2000 due to excess cash being used to pay down debt.

   Interest Expense. Interest expense decreased 41% to $2.0 million in 2001
from $3.4 million in 2000, primarily due to decreases in interest rates.

   Income Taxes. The Company recorded a $0.3 million income tax benefit on
pre-tax income of $1.8 million compared to an income tax expense of $10.1
million on pre-tax income of $23.2 million with an effective tax rate of 44%
in 2000. During 2001, the Company recorded an income tax provision for its
Canadian operations with an effective tax rate of 37% and a tax benefit for
its U.S. operations of $4.6 million due to the U.S. operating loss and a
change in the estimated amount of depletion carryforwards available to reduce
future taxable income. Effective tax rates differing from statutory rates are
primarily due to adjustments upon resolution of audits by Canadian tax
authorities and statutory depletion in the United States.

                                      20
<PAGE>

 2000 Compared to 1999

   Overview. The Company recorded net income of $12,818,000 or $1.47 per share
in 2000, compared to a loss of $206,000, or $0.02 per share, for the
corresponding period of 1999. This improvement results from higher oil and gas
prices and lower general and administrative, restructuring costs and
depreciation, depletion and amortization expenses.

   Revenues. Total revenues increased 63% to $45.5 million in 2000 compared to
$28.0 million in 1999. Oil production decreased 13% to 404 MBbls from 462
MBbls. Natural gas production decreased 8% to 8,369 MMcf from 9,081 MMcf,
resulting in overall production decreasing 9% to 10,793 MMcfe from 11,853
MMcfe. Production decreases are due to normal production declines.

   The Company's average U.S. natural gas price increased 82% to $4.08 per Mcf
in 2000 from $2.24 per Mcf in 1999, while the average Canadian natural gas
price increased 124% to $3.54 from $1.58. The Company's composite average oil
price increased 53% to $26.14 per barrel in 2000 from $17.08 per barrel in
1999. Primarily as a result of price increases, oil and gas revenues increased
68% to $42.3 million in 2000 from $25.2 million in 1999. Plant processing
revenues increased 8% to $1.9 million from $1.8 million primarily as a result
of new third party processing in the Canadian Hanlan-Robb gas processing
plant.

   Production Costs. Production costs increased 19% to $8.0 million in 2000
compared to $6.7 million in 1999 as a result of workover operations for
repairs and production enhancements and production tax increases related to
higher commodity prices. Production costs per Mcfe were $0.74 for 2000 and
$0.57 for 1999. Approximately $0.18 per Mcfe of increased costs are due to
workover operations and increased production taxes.

   Depreciation, Depletion & Amortization (DD&A). Total DD&A decreased 4% to
$9.5 million in 2000 from $9.9 million in 1999. The increase in the oil and
gas DD&A rate per Mcfe to $0.74 in 2000 from $0.69 in 1999 reflects the impact
of previously unevaluated properties evaluated in 2000 and moved into the full
cost pool.

   General and Administrative Expenses. General and administrative expenses
decreased 65% to $1.5 million in 2000 from $4.3 million in 1999 as a result of
the Company's restructuring efforts and the Management Agreement with Kaiser-
Francis.

   Investment Income. Investment income decreased less than 1% to $584,000 in
2000 from $585,000 in 1999.

   Interest Expense. Interest expense decreased 13% to $3.4 million in 2000
from $3.9 million in 1999, reflecting the impact of reduced debt levels,
partially offset by an increase in interest rates.

   Income Taxes. The Company recorded a $10.1 million income tax expense on
pre-tax income of $23.2 million with an effective tax rate of 44% in 2000
compared to an income tax benefit of $954,000 on a pre-tax loss of $1.2
million with an effective tax rate of 82% in 1999. During 2000, the Company
recorded an income tax provision for its Canadian operations with an effective
tax rate of 47% and a tax provision for its U.S. operations with an effective
tax rate of 39%, resulting in an overall effective tax rate of 44%. Effective
tax rates in excess of statutory rates are primarily due to adjustments of
approximately $1.2 million resulting from audits by Canadian tax authorities.

Liquidity and Capital Resources

   As of December 31, 2001, the Company had working capital of $4.0 million as
compared to $9.0 million at December 31, 2000. Cash provided by operating
activities was $13.1 million, $33.2 million and $10.6 million in 2001, 2000
and 1999, respectively.

   The Company's total capital expenditures were $93.8 million ($38.5 million
cash), $7.2 million and $3.3 million for 2001, 2000 and 1999, respectively. In
2001, the Company spent $17.2 million related to the exploration and
development and $76.3 million ($21.0 million of cash expenditures) related to
the acquisition of

                                      21
<PAGE>

Southern Mineral. During 2000, the Company spent $6.9 million related to
exploration and development. In 1999, the Company spent $3.1 million related
to exploration and development.

   In June 1997, the Company entered into a $50 million five-year revolving
credit agreement with the Toronto-Dominion Bank, the agent, and the Bank of
Nova Scotia. The facility was amended in June 1998 to extend the initial five-
year term an additional year to July 1, 2003 with quarterly borrowing base
amortization beginning September 30, 2001.

   In July 2000, the Company entered into a new $75 million revolving credit
agreement with the Toronto-Dominion Bank (TD Bank), the agent, and the Bank of
Nova Scotia. The term of the facility is through April 30, 2003 and the
initial borrowing base was set at $58 million. Borrowings can be funded by
either Eurodollar loans or Base Rate loans. The interest rate on the
borrowings is equal to an interest rate spread plus either the Eurodollar rate
or the Base Rate. The interest spread is determined from a sliding scale based
on the Company's borrowing base percentage utilization in effect from time to
time. The spread ranges from 1.25 to 2.25 on Eurodollar loans and .25 to 1.25
on Base Rate loans. At December 31, 2001, the Company had a total of
$47,300,000 outstanding under the revolver and $10,700,000 available based on
the current borrowing base, as defined, subject to certain limitations. In
2001, the weighted average interest rate under this facility was approximately
5.8%.

   The Company's Canadian subsidiary redeemed its redeemable preferred stock
on August 9, 1994 for $7.0 million and simultaneously issued $7.0 million in
nonrecourse long-term notes payable (Nonrecourse Notes Payable) with similar
financial terms. At December 31, 2001, the nonrecourse long-term notes payable
balance was $1,659,000 million, of which $1,327,000 was classified as
"current."

   The Company has historically funded its capital expenditures, which are
discretionary, and working capital requirements with its cash flow from
operations, debt and equity capital and participation by institutional
investors. If the Company increases its capital expenditure level in the
future or operating cash flow is not as expected, capital expenditures may
require additional funding, obtained through borrowings from commercial banks
and other institutional sources or by public or private offerings of equity or
debt securities.

 Merger with Southern Mineral

   As indicated in Note 4 to the financial statements and part I, Item 1,
"Acquisition, Exploration and Development Activity", PetroCorp completed a
merger with Southern Mineral Corporation in June 2001. Funds needed to
complete this transaction were provided by cash on hand and borrowings under
existing lines of credit.

 Common Stock Repurchases

   On September 14, 2001, the Company announced that the Board of Directors
authorized the purchase of up to 1,000,000 shares of the Company's common
stock. Through December 31, 2001, 264,607 shares have been purchased at a cost
of $2,350,000.

 New Accounting Pronouncements

   In June 2001, the Financial Accounting Standards Board ("FASB") issued FAS
No. 141 and 142. FAS No. 141, Business Combinations, requires the purchase
method of accounting be used for all business combinations initiated after
June 30, 2001. FAS No. 142, Goodwill and Other Intangible Assets, changes the
accounting for goodwill from an amortization method to an impairment-only
approach and is effective January, 2002. The Company believes that adoption of
these new standards will not have an effect on its results of operations or
its financial position. In June 2001, the FASB issued FAS No. 143, Accounting
for Asset Retirement Obligations, and in August 2001, FAS No. 144, Accounting
for Impairment or Disposal of Long-Lived Assets. Management is currently
evaluating the impact of FAS 143 and 144 on financial position and results of
operations.

                                      22
<PAGE>

   Item 7A. Quantitative and Qualitative Disclosure about Market Risk.

   The Company's primary sources of market risk are from fluctuations in
commodity prices, interest rates and exchange rates.

 Commodity Price Risk

   The Company produces and sells natural gas, crude oil, condensate, natural
gas liquids and sulfur. As a result, the Company's financial results can be
significantly affected as these commodity prices fluctuate widely in response
to changing market forces. The Company utilizes hedging transactions to manage
its exposure to price fluctuations on its sales of oil and natural gas. In
2001, as part of the Southern Mineral merger, the Company assumed crude oil
and natural gas costless collars. The impact of these hedging transactions on
2001 financial results was an increase in revenues of $270,000. The estimated
fair value at December 31, 2001 of the crude oil and natural gas collars was
an asset of $644,000. Oil and gas hedges outstanding at December 31, 2001
were:

 Oil Hedges

<TABLE>
<CAPTION>
                                                                            U.S. $
                                                                          NYMEX WTI

    Period                   Total Bbl        Monthly Bbl     Floor          Cap

<S>                       <C>              <C>                <C>    <C>
United States and Canada

Jan-02-Sep-02                 158,500            17,611       $22.00   $25.60 to $27.00

 Gas Hedges
<CAPTION>
                                                                            U.S. $
                                                                     Houston Ship channel

    Period                  Total MMbtu      Monthly MMBtu    Floor          Cap

<S>                       <C>              <C>                <C>    <C>
United States and Canada

Jan-02-Mar-02                 222,000            74,000        $2.75              $4.85

Apr-02-Oct-02                 466,000            66,571        $2.75              $3.80

<CAPTION>
                                                                        CND $ Alberta
                                                                         Spot - AECO

    Period                Total Gigajoules Monthly Gigajoules Floor          Cap

<S>                       <C>              <C>                <C>    <C>
Canada

Jan-02-Sep-02                 450,000            50,000        $4.05              $6.15
</TABLE>

                                      23
<PAGE>

 Interest Rate Risk

   Total debt at December 31, 2001, included no fixed-rate debt. The Company
has elected to use only variable rate financing, therefore the Company has
limited control over interest rate changes, which may adversely affect the
Company's results of operations and cash flows. See Note 6 to the Consolidated
Financial Statements for information regarding future maturities of the
Company's debt.

   As described in Note 7 of the Consolidated Financial Statements of the
Company, an interest rate swap position was assumed as part of the merger with
Southern Mineral. Under the swap, the Company receives a floating rate of the
Canadian prime rate and pays a fixed rate of 5.96% on a notational amount of
Canadian $15 million. The estimated fair value of the swap at December 31,
2001 is a liability of $338,000.

 Foreign Currency Exchange Rate Risk

   The Company conducts a significant portion of its business in the Canadian
dollar and is therefore subject to foreign currency exchange rate risk on cash
flows related to sales, expenses, financing and investing transactions.

Item 8. Financial Statements and Supplementary Data.

   The information required by this item appears on pages 32 through 60 of
this report.

Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.

   There is no matter required to be disclosed in response to this item.

                                   PART III

   In accordance with paragraph (3) of General Instruction G to Form 10-K,
Part III of this Report is omitted because the Company will file with the
Securities and Exchange Commission not later than 120 days after the end of
the fiscal year ended December 31, 2001 a definitive proxy statement pursuant
to Regulation 14A involving the election of directors, which proxy statement
is incorporated herein by reference (with the exception of certain portions
noted therein that are not so incorporated by reference).

                                      24
<PAGE>

                                    PART IV

Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.

   (a) The following documents are filed as a part of this report:

   1. Financial Statements

<TABLE>
<CAPTION>
                                                                         Page
                                                                          of
                                                                         this
                                                                        Report
                                                                        ------
<S>                                                                     <C>
Report of Independent Accountants......................................   31
Consolidated Balance Sheets as of December 31, 2001 and December 31,
 2000..................................................................   32
Consolidated Statements of Operations for the Years Ended December 31,
 2001, 2000 and 1999...................................................   33
Consolidated Statements of Shareholders' Equity for the Years Ended
 December 31, 2001, 2000 and 1999......................................   34
Consolidated Statements of Cash Flows for the Years Ended December 31,
 2001, 2000 and 1999...................................................   35
Notes to Consolidated Financial Statements.............................   37
</TABLE>

   2. Financial Statement Schedules

     Not Applicable.

   3. Exhibits

<TABLE>
 <C>  <S>
 2.1* Plan of Merger and Combination Agreement, dated September 18, 1991, by
      and among Park Avenue Exploration Corporation, PetroCorp, L.S. Holding
      Company, PetroCorp Incorporated, PetroPartners Limited Partnership,
      PetroCorp Acquisition Corporation and Management Shareholders, as amended
      by the First Amendment, dated October 1, 1992, and by the Simplification
      Agreement described in Exhibit 2.2 hereto. Incorporated by reference to
      Exhibit 2.1 to the Company's Registration Statement on
      Form S-1 (Registration No. 33-36972) initially filed with the Securities
      and Exchange Commission (SEC) on August 26, 1993 (Registration
      Statement).
 2.2* Simplification Agreement, dated August 24, 1993, by and among Park Avenue
      Exploration Corporation, L.S. Holding Company, PetroCorp, PetroCorp
      Incorporated, PetroPartners Limited Partnership, PetroCorp Employees
      Partnership, L.P., Lealon L. Sargent, W. Neil McBean, Don A. Turkleson,
      Michael L. Lord, Antonio F. Pelletier, David G. Campbell, Fletcher S.
      Hicks, Craig K. Townsend, Clifford G. Zwahlen, Charles L. Zorio, Rodney
      Rother, Mark Meyer and Carl Campbell (Simplification Agreement).
      Incorporated by reference to Exhibit 2.2 to the Registration Statement.
 3.1* Amended and Restated Articles of Incorporation of PetroCorp Incorporated.
      Incorporated by reference to Exhibit 3.2 to the Registration Statement.
 3.2* Amended and Restated Bylaws of PetroCorp Incorporated. Incorporated by
      reference to Exhibit 3.2 to the Company's Quarterly Report on Form 10-Q
      for the quarterly period ended June 30, 1996.
 3.3* Statement of Designations, Preferences, Limitations and Relative Rights
      of Its Series A Junior Participating Preferred Stock. Incorporated by
      reference to Exhibit 3.1 to the Company's Form 8-K, dated November 20,
      1998.
 4.1* Rights Agreement dated as of November 12, 1998, between PetroCorp
      Incorporated and First Union National Bank, as Rights Agent. Incorporated
      by reference to Exhibit 4.1 to the Company's Form 8-K, dated November 20,
      1998.
 4.2* Form of Right Certificate. Incorporated by reference to Exhibit 4.2 to
      the Company's Form 8-K, dated November 20, 1998.
 4.3* Specimen certificate for shares of Common Stock. Incorporated by
      reference to Exhibit 4.1 to the Registration Statement.
</TABLE>

                                       25
<PAGE>

<TABLE>
 <C>    <S>
  4.4*  Note Purchase Agreement, dated July 29, 1993, among PetroCorp
        Incorporated, United States Fidelity and Guaranty Company, Connecticut
        General Life Insurance Company, Indiana Insurance Company, Security
        Life of Denver Insurance Company, Southland Life Insurance Company,
        Life Insurance Company of Georgia and Life Insurance Company of North
        America. Incorporated by reference to Exhibit 4.2 to the Registration
        Statement.
  9.1*  Voting Agreement, dated January 18, 1994, by and among USF&G
        Corporation, Park Avenue Exploration Corporation, United States
        Fidelity and Guaranty Company, CIGNA Corporation, L.S. Holding Company,
        American Oil & Gas Investors, AmGO II, First Reserve Fund V, Limited
        Partnership, First Reserve Fund V-2, Limited Partnership, First Reserve
        Fund VI, Limited Partnership and First Reserve Corporation.
        Incorporated by reference to Exhibit 9.2 to the Form 8-K.
 10.1*  Amended and Restated 1992 PetroCorp Stock Option Plan. Incorporated by
        reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-
        Q for the quarterly period ended September 30, 1996.
 10.2*  Hanlan-Robb Area Agreement of Purchase and Sale, effective August 1,
        1991, between Gulf Canada Resources Limited and Petro-Canada and PCC
        Energy Inc. Incorporated by reference to Exhibit 10.3 to the
        Registration Statement.
 10.3*  Registration Rights Agreement, dated August 24, 1993, between L.S.
        Holding Company (assigned to Kaiser-Francis Oil Company) and PetroCorp
        Incorporated. Incorporated by reference to Exhibit 10.5 to the
        Registration Statement.
 10.4*  Registration Rights Agreement, dated August 24, 1993, between Park
        Avenue Exploration Corporation and PetroCorp Incorporated. Incorporated
        by reference to Exhibit 10.6 to the Registration Statement.
 10.5*  Registration Rights Agreement, dated January 18, 1994, between
        PetroCorp Incorporated and American Oil & Gas Investors, AmGO II, First
        Reserve Fund V, Limited Partnership, First Reserve Fund V-2, Limited
        Partnership, First Reserve Fund VI, Limited Partnership and First
        Reserve Corporation (assigned to Kaiser-Francis Oil Company).
        Incorporated by reference to Exhibit 10.1 to the Form 8-K.
 10.6*  Piggyback Registration Rights Agreement, dated October 27, 1993,
        between Lealon L. Sargent and PetroCorp Incorporated. Incorporated by
        reference to Exhibit 10.6 to the Company's Annual Report on Form 10-K
        for the fiscal year ended December 31, 1993. This is a management
        contract or compensatory plan or arrangement required to be filed as an
        exhibit.
 10.7*  Separation Benefits Agreement, dated September 27, 1993, between Lealon
        L. Sargent and PetroCorp Incorporated. Incorporated by reference to
        Exhibit 10.8 to the Registration Statement. This is a management
        contract or compensatory plan or arrangement required to be filed as an
        exhibit.
 10.8*  Executive Management Annual Incentive Compensation Plan, effective
        January 1, 1994. Incorporated by reference to Exhibit 10.8 to the
        Company's Annual Report on Form 10-K for the fiscal year ended December
        31, 1994 (1994 Form 10-K). This is a management contract or
        compensatory plan or arrangement required to be filed as an exhibit.
 10.9*  Share Purchase Agreement, dated December 13, 1996, between 702056
        Alberta Ltd. and shareholders of Millarville Oil & Gas Ltd.
        Incorporated by reference to Exhibit 2 to the Company's Current Report
        on Form 8-K, dated December 23, 1996.
 10.10* Agreement for Purchase and Sale, dated June 5, 1997, between PetroCorp
        Incorporated and Great River Oil and Gas Corporation. Incorporated by
        reference to Exhibit 2.1 to the Company's Current Report on Form 8-K
        dated July 1, 1997.
 10.11* First Amendment to Agreement for Purchase and Sale, dated June 30,
        1997, between PetroCorp Incorporated and Great River Oil and Gas
        Corporation. Incorporated by reference to Exhibit 2.2 to the Company's
        Current Report on Form 8-K dated July 1, 1997.
</TABLE>

                                       26
<PAGE>

<TABLE>
 <C>    <S>
 10.12* Credit Agreement, dated June 26, 1997, among PetroCorp Incorporated,
        PCC Energy Limited, PCC Energy Corp, and Toronto-Dominion (Texas), Inc.
        and Toronto-Dominion Bank. Incorporated by reference to Exhibit 10 to
        the Company's current report on Form 8-K dated July 1, 1997.
 10.13* 1997 Non-Employee Director Stock Option Plan. Incorporated by reference
        to Appendix A to the Company's Proxy Statement for the Annual Meeting
        of Shareholders held on May 16, 1997.
 10.14* Management Agreement, dated August 3, 1999, between PetroCorp
        Incorporated and Kaiser-Francis Oil Company. Incorporated by reference
        to Annex A of the Company's Proxy Statement dated September 30, 1999.
 10.15* Credit Agreement dated July 21, 2000 among PetroCorp Incorporated, PC
        Energy Limited, PCC Corp., Toronto Dominion (Texas), Inc., The Toronto-
        Dominion Bank, TD Securities (USA), Inc. and various lenders signature
        thereto. Incorporated by reference to Exhibit 10.2 of the Company's
        Quarterly report on Form 10-Q dated August 11, 2000.
 10.16* PetroCorp Incorporated 2000 Stock Option Plan. Incorporated by
        reference to exhibit 4.0 of the company's registration of such plan on
        form S-8 filed on December 12, 2000.
 10.17* Southern Mineral Corporation 1995 Non-employee Director Compensation
        Plan (incorporated by reference to exhibit (k) to the Southern
        Mineral's annual report on Form 10-k dated December 31, 1994
        (Commission File No. No 0-8043)).
 10.18* Southern Mineral 1996 Stock Option Plan (incorporated by reference to
        Exhibit 10.10 to Southern Mineral's Form 10-KSB dated December 31, 1995
        (Commission File No. 0-8043)).
 10.19* Southern Mineral 1997 Stock Option Plan (incorporated by reference to
        Southern Mineral's Form S-8, filed April 28, 1998, Registration No.
        333-512 (Commission file No. 333-420450)).
 10.20* Southern Mineral 1997 Non-employee Director Compensation Plan
        (incorporated by reference to Southern Mineral's Form S-8, filed April
        28, registration No. 333-512 (Commission file No. 333-26001)).
 10.21* Southern Mineral Stock Option Agreement made as of December 31, 1994
        between Southern Mineral Corporation and Steven H. Mikel (incorporated
        by reference to Exhibit (h) to the Company's annual report on form 10-K
        for year ended December 31, 1994 (commission File NO. 0-8043)).
 10.22* Employment Agreement, dated December 28, 2001, between PetroCorp
        Incorporated and Gary R. Christopher. (Incorporated by reference to
        PetroCorp's 2001 Form 10-K filed March 26, 2002).
 10.23* Employment Agreement, dated December 28, 2001, between PetroCorp
        Incorporated and Richard L. Dunham. (Incorporated by reference to
        PetroCorp's 2001 Form 10-K filed March 26, 2002).
 21*    List of material subsidiaries. (Incorporated by reference to
        PetroCorp's 2001 Form 10-K filed March 26, 2002).
 23.1*  Consent of PricewaterhouseCoopers LLP. (Incorporated by reference to
        PetroCorp's 2001 Form 10-K filed March 26, 2002).
 23.2*  Consent of Huddleston & Co., Inc. (Incorporated by reference to
        PetroCorp's 2001 Form 10-K filed March 26, 2002).
 99.1*  Agreement to furnish document relating to subsidiary. Incorporated by
        reference to Exhibit 99.1 to the 1994 Form 10-K.
</TABLE>
--------
*  Incorporated by reference.

    (b) Reports on Form 8-K

   None.

                                       27
<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.

                                          PetroCorp Incorporated
                                          (Registrant)

                                                /s/ Gary R. Christopher
                                          By: _________________________________
                                                    Gary R. Christopher
                                               President and Chief Executive
                                                          Officer
                                               (Principal Executive Officer)

Date: April 4, 2002

   Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.

<TABLE>
<CAPTION>
              Signature                          Title                   Date
              ---------                          -----                   ----

<S>                                    <C>                        <C>
     /s/ Gary R. Christopher           President, Chief Executive    April 4, 2002
______________________________________  Officer (Principal
         Gary R. Christopher            Executive Officer) and
                                        Director

       /s/ Steven R. Berlin            Vice President--Finance,      April 4, 2002
______________________________________  Secretary & Treasurer
           Steven R. Berlin             (Principal Financial
                                        Officer and Principal
                                        Accounting Officer) and
                                        Director

        /s/ Steven E. Amos             Controller                    April 4, 2002
______________________________________
            Steven E. Amos

      /s/ Lealon L. Sargent            Chairman of the Board of      April 4, 2002
______________________________________  Directors
          Lealon L. Sargent

      /s/ Thomas N. Amonett            Director                      April 4, 2002
______________________________________
          Thomas N. Amonett

       /s/ Paul J. Coughlin            Director                      April 4, 2002
______________________________________
           Paul J. Coughlin

        /s/ Mark W. Files              Director                      April 4, 2002
______________________________________
            Mark W. Files
</TABLE>


                                      28
<PAGE>

<TABLE>
<CAPTION>
              Signature                          Title                   Date
              ---------                          -----                   ----

<S>                                    <C>                        <C>
       /s/ Thomas R. Fuller            Director                      April 4, 2002
______________________________________
           Thomas R. Fuller

        /s/ W. Neil McBean             Director                      April 4, 2002
______________________________________
            W. Neil McBean

       /s/ Robert C. Thomas            Director                      April 4, 2002
______________________________________
           Robert C. Thomas
</TABLE>

                                       29
<PAGE>

                                 EXHIBIT INDEX

<TABLE>
<CAPTION>
 No.  Item
 <C>  <S>
 21   -- List of material subsidiaries
 23.1 -- Consent of PricewaterhouseCoopers LLP
 23.2 -- Consent of Huddleston & Co., Inc.
</TABLE>

                                       30
<PAGE>

                       REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Shareholders of
PetroCorp Incorporated

   In our opinion, the accompanying consolidated balance sheets and the
related consolidated statements of operations, shareholders' equity and cash
flows present fairly, in all material respects, the financial position of
PetroCorp Incorporated and its subsidiaries (the "Company") at December 31,
2001 and 2000, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 2001, in conformity
with accounting principles generally accepted in the United States of America.
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 financial statements in
accordance with auditing standards generally accepted in the United States of
America, 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 our opinion.

                                          PricewaterhouseCoopers LLP

Tulsa, Oklahoma
March 15, 2002

                                      31
<PAGE>

                             PETROCORP INCORPORATED

                          CONSOLIDATED BALANCE SHEETS
                           December 31, 2001 and 2000
                      (in thousands, except share amounts)

<TABLE>
<CAPTION>
                                                             2001       2000
                                                           ---------  --------
<S>                                                        <C>        <C>
                          ASSETS
Current assets:
  Cash and cash equivalents............................... $   1,265  $ 21,946
  Accounts receivable, net................................    13,267    13,332
  Other current assets....................................     1,411       609
                                                           ---------  --------
    Total current assets..................................    15,943    35,887
                                                           ---------  --------
Property, plant and equipment:
  Oil and gas properties, at cost, full cost method, net
   of accumulated depreciation, depletion, amortization
   and impairment.........................................   126,925    68,432
  Other, net..............................................     1,527     2,504
                                                           ---------  --------
                                                             128,452    70,936
                                                           ---------  --------
Deferred income taxes.....................................    18,261    10,254
Other assets, net.........................................     2,699       242
                                                           ---------  --------
    Total assets.......................................... $ 165,355  $117,319
                                                           =========  ========
           LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
  Accounts payable........................................ $   6,708  $ 17,732
  Accrued liabilities.....................................     3,877     2,488
  Income tax payable......................................        --     5,444
  Current portion of long-term debt.......................     1,327     1,194
                                                           ---------  --------
    Total current liabilities.............................    11,912    26,858
                                                           ---------  --------
Long-term debt............................................    47,620    29,992
                                                           ---------  --------
Deferred income taxes.....................................    13,908     6,192
                                                           ---------  --------
Commitments and contingencies (Note 13)
Shareholders' equity:
  Preferred stock, $0.01 par value, 1,000,000 shares
   authorized,
   none issued............................................        --        --
  Common stock, $0.01 par value, 25,000,000 shares
   authorized,
   (12,556,109 shares and 8,703,719 shares outstanding
   at December 31, 2001 and 2000, respectively)...........       128        87
  Additional paid-in capital..............................   111,114    71,614
  Accumulated deficit.....................................    (9,666)  (11,712)
  Accumulated other comprehensive loss....................    (7,311)   (5,712)
  Treasury stock, at cost (264,607 shares)................    (2,350)       --
                                                           ---------  --------
   Total shareholders' equity.............................    91,915    54,277
                                                           ---------  --------
    Total liabilities and shareholders' equity............ $ 165,355  $117,319
                                                           =========  ========
</TABLE>

   The accompanying notes are an integral part of these financial statements.

                                       32
<PAGE>

                             PETROCORP INCORPORATED

                     CONSOLIDATED STATEMENTS OF OPERATIONS
                  Years Ended December 31, 2001, 2000 and 1999
                      (in thousands, except share amounts)

<TABLE>
<CAPTION>
                                                      2001     2000     1999
                                                     -------  -------  -------
<S>                                                  <C>      <C>      <C>
Revenues:
  Oil and gas....................................... $48,058  $42,264  $25,162
  Plant processing..................................   1,817    1,934    1,785
  Other.............................................   1,399    1,278    1,079
                                                     -------  -------  -------
                                                      51,274   45,476   28,026
                                                     -------  -------  -------
Expenses:
  Production costs..................................  12,997    8,038    6,733
  Depreciation, depletion and amortization..........  16,944    9,471    9,906
  Oil and gas property valuation adjustment.........  15,400       --       --
  General and administrative........................   2,259    1,529    4,311
  Restructuring costs...............................      --     (445)   3,643
  Other operating expenses..........................   1,485    1,212    1,181
                                                     -------  -------  -------
                                                      49,085   19,805   25,774
                                                     -------  -------  -------
Income from operations..............................   2,189   25,671    2,252
                                                     -------  -------  -------
Other income (expenses):
  Investment income.................................     143      584      585
  Interest expense..................................  (1,991)  (3,381)  (3,865)
  Other income (expenses)...........................   1,425      295     (132)
                                                     -------  -------  -------
                                                        (423)  (2,502)  (3,412)
                                                     -------  -------  -------
Income (loss) before income taxes...................   1,766   23,169   (1,160)
                                                     -------  -------  -------
Income tax provision (benefit):
  Current...........................................   5,552    5,497       --
  Deferred..........................................  (5,832)   4,612     (954)
                                                     -------  -------  -------
                                                        (280)  10,109     (954)
                                                     -------  -------  -------
Net income (loss) before extraordinary item.........   2,046   13,060     (206)
Extraordinary loss--extinguishment of debt (less
 applicable tax benefit of $143)....................      --      242       --
                                                     -------  -------  -------
Net income (loss)................................... $ 2,046  $12,818  $  (206)
                                                     =======  =======  =======
Net income (loss) per common share--basic:
  Income (loss) before extraordinary item........... $  0.19  $  1.50  $ (0.02)
  Extraordinary item................................      --    (0.03)      --
                                                     -------  -------  -------
  Net income (loss)................................. $  0.19  $  1.47  $ (0.02)
                                                     =======  =======  =======
  Net income (loss) per common share--diluted:
  Income (loss) before extraordinary item........... $  0.18  $  1.49  $ (0.02)
  Extraordinary item................................      --    (0.03)      --
                                                     -------  -------  -------
  Net income (loss)................................. $  0.18  $  1.46  $ (0.02)
                                                     =======  =======  =======
Weighted average number of common shares--basic.....  10,975    8,692    8,658
                                                     =======  =======  =======
Weighted average number of common shares--diluted...  11,119    8,786    8,658
                                                     =======  =======  =======
</TABLE>

   The accompanying notes are an integral part of these financial statements.

                                       33
<PAGE>

                             PETROCORP INCORPORATED

                CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
                                 (in thousands)

<TABLE>
<CAPTION>
                                                                Accumulated
                         Common Stock   Additional                 other
                         --------------  paid-in   Accumulated comprehensive Treasury
                         Shares  Amount  capital     deficit       loss       stock     Total
                         ------  ------ ---------- ----------- ------------- --------  -------
<S>                      <C>     <C>    <C>        <C>         <C>           <C>       <C>
Balance, December 31,
 1998...................  8,656     87     71,245    (24,324)      (6,264)        --   $40,744
 Net loss...............     --     --         --       (206)          --         --      (206)
 Exercise of stock
  options...............     27     --        135         --           --         --       135
 Other comprehensive
  income................     --     --         --         --        1,690         --     1,690
                         ------   ----   --------    -------      -------    -------   -------
Balance, December 31,
 1999...................  8,683     87     71,380    (24,530)      (4,574)        --    42,363
 Net income.............     --     --         --     12,818           --         --    12,818
 Exercise of stock
  options...............     21     --        234         --           --         --       234
 Other comprehensive
  loss..................     --     --         --         --       (1,138)        --    (1,138)
                         ------   ----   --------    -------      -------    -------   -------
Balance, December 31,
 2000...................  8,704     87     71,614    (11,712)      (5,712)        --    54,277
 Net income.............     --     --         --      2,046           --         --     2,046
 Shares issued--merger..  4,000     40     38,578         --           --         --    38,618
 Exercise of stock
  options...............    117      1        922         --           --         --       923
 Other comprehensive
  loss..................     --     --         --         --       (1,599)        --    (1,599)
 Treasury stock.........   (265)    --         --         --           --     (2,350)   (2,350)
                         ------   ----   --------    -------      -------    -------   -------
Balance, December 31,
 2001................... 12,556   $128   $111,114    $(9,666)     $(7,311)   $(2,350)  $91,915
                         ======   ====   ========    =======      =======    =======   =======
</TABLE>


   The accompanying notes are an integral part of these financial statements.

                                       34
<PAGE>

                            PETROCORP INCORPORATED

                   CONSOLIDATED STATEMENTS OF CASH FLOWS(A)
                 Years Ended December 31, 2001, 2000 and 1999
                                (in thousands)

<TABLE>
<CAPTION>
                                                    2001       2000     1999
                                                  ---------  --------  -------
<S>                                               <C>        <C>       <C>
Cash flows from operating activities:
 Net income (loss)............................... $   2,046  $ 12,818  $  (206)
 Ajustments to reconcile net income (loss) to net
  cash provided by operating activities:
  Extraordinary loss.............................        --       242       --
  Depreciation, depletion and amortization.......    16,944     9,471    9,906
  Deferred income tax expense (benefit)..........    (5,832)    4,612     (954)
  Oil and gas property valuation adjustment......    15,400        --       --
  Other..........................................       142       107     (112)
 Changes in operating assets and liabilities (net
  of assets acquired and liabilities assumed in
  the acquisition of Southern Mineral):
  Accounts receivable............................     5,343    (8,727)     (36)
  Other current assets...........................       707      (447)     164
  Accounts payable...............................   (13,761)   11,594    1,714
  Accrued liabilities............................    (2,569)   (1,923)     142
  Income taxes payable...........................    (5,317)    5,444       --
                                                  ---------  --------  -------
    Net cash provided by operating activities....    13,103    33,191   10,618
                                                  ---------  --------  -------
Cash flows from investing activities:
 Proceeds from sale of oil and gas properties....        --       210       --
 Additions to oil and gas properties.............   (17,171)   (6,862)  (3,089)
 Additions to plant and related facilities.......      (366)     (525)    (166)
 Purchase of Southern Mineral Corporation, net of
  cash acquired (See Supplemental disclosure)....   (20,989)       --       --
 Additions to other assets.......................        --       (16)      --
                                                  ---------  --------  -------
    Net cash used in investing activities........   (38,526)   (7,193)  (3,255)
                                                  ---------  --------  -------
Cash flows from financing activities:
 Proceeds from long-term debt....................   134,763    30,030    2,238
 Repayment of long-term debt.....................  (129,273)  (46,714)  (4,566)
 Purchase of treasury shares.....................    (2,350)       --       --
 Other...........................................       401      (142)     135
                                                  ---------  --------  -------
    Net cash provided by (used in) financing
     activities..................................     3,541   (16,826)  (2,193)
                                                  ---------  --------  -------
Effect of exchange rate changes on cash..........     1,201      (125)     (57)
                                                  ---------  --------  -------
Net increase (decrease) in cash and cash
 equivalents.....................................   (20,681)    9,047    5,113
Cash and cash equivalents at beginning of year...    21,946    12,899    7,786
                                                  ---------  --------  -------
Cash and cash equivalents at end of year......... $   1,265  $ 21,946  $12,899
                                                  =========  ========  =======
</TABLE>
--------
(A) The first supplemental disclosure to this statement provides necessary
    information to fully understand the economics of the Southern Mineral
    transaction. Attempting to understand the economics of the Company,
    without understanding the impact of the disclosure could lead to erroneous
    conclusions. Current GAAP, however, requires that the information be
    supplementarily disclosed and not in the body of this statement.

  The accompanying notes are an integral part of these financial statements.

                                      35
<PAGE>

                             PETROCORP INCORPORATED

                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                  Years Ended December 31, 2001, 2000 and 1999
                                 (in thousands)

Supplemental disclosures:

   1. Significant differences between balance sheet changes and amounts shown
in the Statement of Cash Flows for December 31, 2001 resulted from the purchase
of Southern Mineral net assets. Additional differences include the impact of
hedging activities and foreign currency translations. The following summarizes
the details of the fair value of assets acquired and liabilities assumed in the
acquisition of Southern Mineral:

<TABLE>
      <S>                                                             <C>
      Accounts receivable............................................ $   5,278
      Other current assets...........................................       582
      Oil and gas properties.........................................    76,324
      Other assets...................................................     6,508
                                                                      ---------
        Total assets acquired........................................    88,692
                                                                      ---------
      Accounts payable...............................................    (2,737)
      Accrued liabilities............................................    (4,100)
      Debt assumed...................................................   (12,583)
      Other liabilities..............................................    (9,241)
                                                                      ---------
        Total liabilities assumed....................................   (28,661)
                                                                      ---------
      Legal, professional and other costs............................      (424)
      Financed through issue of common stock
       (net of $380 registration costs)                                (38,618)
                                                                      ---------
      Shown as purchase of Southern Mineral
       Corporation on Statement of Cash Flows........................  $ 20,989
                                                                      =========
</TABLE>

<TABLE>
<CAPTION>
                          2001    2000   1999
                         ------- ------ ------
   <S>                   <C>     <C>    <C>
   2. Interest paid      $ 1,861 $3,423 $3,150
   3. Income taxes paid  $13,346 $   -- $   --
</TABLE>

   4. In 2001, 2000 and 1999, the Company issued $311,000, $525,000 and
$238,000 of additional notes, respectively, as provided under the provisions of
the agreements to finance the company's portion of plant capital additions (See
Note 6).

   The accompanying notes are an integral part of these financial statements.

                                       36
<PAGE>

                            PETROCORP INCORPORATED

                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

                       December 31, 2001, 2000 and 1999

1. Summary of Accounting Policies

 General

   PetroCorp Incorporated, a Texas corporation, is engaged in the acquisition,
exploration, development, and the production and sale of crude oil and natural
gas in North America. The terms "PetroCorp" and "Company" refer to PetroCorp
Incorporated and its subsidiaries. PetroCorp operates in Canada through its
wholly-owned Canadian subsidiaries PCC Energy Inc. (PCC Inc.) and PCC Energy
Corp. In the United States, PetroCorp conducts business in its own name and
that of its U.S. subsidiaries, BEC Energy Inc. and PetroCorp Acquisition
Company.

 Principles of Consolidation

   The accompanying consolidated financial statements include the accounts of
Petrocorp Incorporated and its wholly-owned subsidiaries. All significant
intercompany accounts and transactions have been eliminated.

 Use of Estimates

   The preparation of financial statements in conformity with generally
accepted accounting principles requires the Company to make estimates and
assumptions that affect the amounts reported in the financial statements and
the accompanying notes. Actual results may differ from such estimates. In
addition, the oil and gas reserve data and the deferred tax asset include
significant estimates which, in the near term, could materially differ from
the amounts ultimately realized.

 Property, Plant and Equipment

   The Company follows the full cost method of accounting for oil and gas
properties whereby all productive and nonproductive exploration and
development costs incurred for the purpose of finding oil and gas reserves are
capitalized. Such capitalized costs include lease acquisition, geological and
geophysical work, delay rentals, drilling, completing and equipping oil and
gas wells, together with internal costs directly attributable to property
acquisition, exploration and development activities. No gains or losses are
recognized upon the sale or other disposition of oil and gas properties,
except in unusually significant transactions.

   The costs of the Company's oil and gas properties, including estimated
future development and dismantlement costs, are depreciated on a country-by-
country basis using a composite unit-of-production rate. An additional
valuation adjustment is made on a country-by-country basis if net capitalized
costs of the Company's oil and gas properties exceed the ceiling, which is
calculated on a quarterly basis as the sum of (1) the present value (10%) of
future net revenues from estimated production of proved oil and gas reserves
plus (2) the lower of cost or estimated fair value of the unproved properties,
less (3) the related income tax effects. In the year ended December 31, 2001,
there was a valuation adjustment of $15,400,000. There was no valuation
adjustment for the years ended December 31, 2000 and 1999.

   Plant and related facilities, consisting principally of a gas processing
plant in Alberta, Canada, are being depreciated on a straight-line basis over
the remaining estimated useful life. Other property and equipment are
depreciated by the straight-line method at rates based on the estimated useful
lives of the assets ranging from five to ten years.

                                      37
<PAGE>

                            PETROCORP INCORPORATED

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                       December 31, 2001, 2000 and 1999


 Revenue Recognition

   Revenues from the sale of petroleum produced are recognized upon the
passage of title, net of royalties and net profits royalty interests. In 2001,
the company changed its accounting for transportation and gathering costs to
include those charges in other revenues and other operating expenses. Revenues
and operating expenses for 2000 and 1999 have been increased by $903,000 and
$900,000 to conform to the new presentation. This reclassification had no
effect on income from operations.

   Revenues from natural gas production are recorded using the sales method,
net of royalties and net profits interests, which may result in more or less
than the Company's share of pro-rata production from certain wells. The
Company estimates its balancing position to be approximately $390,000 (244,000
mcf) on underproduced properties and approximately $331,000 (207,000 mcf) on
overproduced properties. When sales volumes exceed the Company's entitled
share and the overproduced balance exceeds the Company's share of the
remaining estimated proved natural gas reserves for a given property, the
Company records a liability. At December 31, 2001 and 2000, the Company
included $171,000 (120,000 mcf) and $53,000 (33,000 mcf) respectively, in
accrued liabilities with respect to overproduced imbalances. The Company's
policy is to expense the pro-rata share of lease operating costs from all
wells as incurred. Such expenses relating to the balancing position on wells
in which the Company has imbalances are not significant.

   Revenues from plant processing are recognized at the time associated
natural gas is processed. Other revenues include fees associated with the
Company's U.S. gathering system and from the sale of sulfur in Canada.

 Accounts Receivable

   Accounts receivable relate primarily to sales of oil and gas and amounts
due from joint-interest partners for expenditures made by the Company on
behalf of such partners. The Company reviews the financial condition of
potential purchasers and partners prior to signing sales or joint-interest
agreements. At December 31, 2001 and 2000, the Company's allowance for
doubtful accounts receivable was not significant.

 Income Taxes

   The Company utilizes the asset and liability method under which deferred
tax assets and liabilities are recognized for the estimated future tax
consequences attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases.

 Foreign Currency Translation

   The "functional currency" for translating the Company's Canadian accounts
is the Canadian dollar. Assets and liabilities are translated into the
reporting currency at the rate of exchange in effect at the balance sheet date
while revenues, expenses, gains and losses are translated at the average
exchange rate for the period. The resulting translation adjustments are
accumulated in the other comprehensive loss component of shareholders' equity.
Foreign currency transaction gains and losses are recognized currently. For
the year ended December 31, 2001, the Company recognized a foreign currency
transaction gain of $916,000. For the years ended December 31, 2000 and 1999,
the Company recognized foreign currency transaction losses of $98,000 and
$22,000, respectively.

                                      38
<PAGE>

                            PETROCORP INCORPORATED

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                       December 31, 2001, 2000 and 1999


 Cash Equivalents

   For purposes of the consolidated statement of cash flows, the Company
considers all highly liquid debt instruments purchased with a maturity date of
three months or less at the date of purchase to be cash equivalents. Cash and
cash equivalents are not insured above FDIC limits, which subjects the Company
to credit risk.

 Hedging Activities

   To reduce the impact of fluctuations in the market prices of oil and
natural gas, the Company periodically utilizes hedging strategies such as
futures transactions or swaps to hedge the price of a portion of its future
oil and natural gas production. Results of these hedging transactions are
reflected in oil and natural gas sales in the month of hedged production. In
2001, the impact of hedging transactions was a net increase in revenues of
$270,000. In 2000, the impact of hedging transactions was a net reduction of
revenues by $1,097,000. No hedging transactions occurred in 1999.

   On June 15, 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities". SFAS 133, as amended, was effective
January 1, 2001 for the Company. SFAS 133 requires that all derivative
instruments be recorded on the balance sheet at their fair value. Changes in
the fair value of derivatives are recorded each period in current earnings or
other comprehensive income (only certain types of hedge transactions are
reported as a component of other comprehensive income). Additionally, for all
hedge transactions the nature and type of hedge is disclosed.

 Reclassification

   Certain prior year balances have been reclassified to conform with the
current year financial statement presentation.

 Other

   In June 2001, the Financial Accounting Standards Board ("FASB") issued FAS
No. 141 and 142. FAS No. 141, Business Combinations, requires the purchase
method of accounting be used for all business combinations initiated after
June 30, 2001. FAS No. 142, Goodwill and Other Intangible Assets, changes the
accounting for goodwill from an amortization method to an impairment-only
approach and is effective January, 2002. The Company believes that adoption of
these new standards will not have an effect on its results of operations or
its financial position. In June 2001, the FASB issued FAS No. 143, Accounting
for Asset Retirement Obligations, and in August 2001, FAS No. 144, Accounting
for Impairment or Disposal of Long-Lived Assets. Management is currently
evaluating the impact of FAS 143 and 144 on financial position and results of
operations.

2. Restructuring

   As part of a restructuring plan, on August 3, 1999, PetroCorp's Board of
Directors entered into a Management Agreement with its largest shareholder,
Kaiser-Francis Oil Company ("Kaiser-Francis"), under which Kaiser-Francis
provides management, technical, and administrative support services for all
PetroCorp operations in the United States and Canada.

   As a result of the restructuring, fifty-two employees were terminated in
1999 with one employee terminated in 2000. Several employees elected to defer
receipt of their termination benefits until 2000. The Houston,

                                      39
<PAGE>

                            PETROCORP INCORPORATED

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                       December 31, 2001, 2000 and 1999

Oklahoma City and Calgary offices were closed but the Company was still liable
under the lease agreements. In the second quarter of 2000, the Company was
able to find a replacement lessee for some of the idle office space earlier
than anticipated.

   The company recorded restructuring costs of $3,643,000 during 1999.
Included in the costs are employee termination costs of $2,371,000, $807,000
in nonrefundable office lease discontinuance, $363,000 in investment banking
and legal costs, and $102,000 in other related costs.

   The following table shows the change in accrued restructuring costs during
2001 (in thousands):

<TABLE>
<CAPTION>
                                          Expenditures
                              Balance at    charged                Balance at
                             December 31,   against    Changes in December 31,
                                 2000       accrual     estimate      2001
                             ------------ ------------ ---------- ------------
<S>                          <C>          <C>          <C>        <C>
Office lease discontinuance
 and other
 related costs..............      70           70          --          --
                                 ---          ---         ---         ---
                                 $70          $70         $--         $--
                                 ===          ===         ===         ===
</TABLE>

3. Comprehensive Income

   The Company follows SFAS No. 130, "Reporting Comprehensive Income." This
Statement establishes requirements for reporting comprehensive income and its
components which includes the Company's foreign currency translation
adjustments. The Company's comprehensive income (loss) for the years ended
December 31, 2001, 2000 and 1999 are as follows (amounts in thousands):

<TABLE>
<CAPTION>
                                                      Years ended December
                                                              31,
                                                     ------------------------
                                                      2001     2000     1999
                                                     -------  -------  ------
      <S>                                            <C>      <C>      <C>
      Net income (loss)............................. $ 2,046  $12,818  $ (206)
                                                     -------  -------  ------
      Derivative hedging gain (net of taxes of
       $679)........................................   1,057       --      --
      Reclassification of hedging gain to income
       (net of taxes of $105)                           (165)      --      --
      Foreign currency translation..................  (2,491)  (1,138)  1,690
                                                     -------  -------  ------
                                                      (1,599)  (1,138)  1,690
                                                     -------  -------  ------
      Comprehensive income (loss)................... $   447  $11,680  $1,484
                                                     =======  =======  ======
</TABLE>

   Accumulated other comprehensive loss was comprised solely of foreign
currency translation loss through December 31, 2000. As of December 31, 2001,
accumulated other comprehensive loss included $892 of derivative hedging gain,
net of taxes and $8,203 of foreign currency translation losses.

4. Merger with Southern Mineral Corporation

   PetroCorp completed the acquisition of Southern Mineral on June 6, 2001.
Southern Mineral shareholders could elect to receive .471 shares of PetroCorp
common stock or cash of $4.71 or some combination thereof for each share of
Southern Mineral common stock they owned. Based on elections of Southern
Mineral shareholders, PetroCorp issued 4 million shares (valued at
approximately $39 million) and paid cash of approximately $21.4 million. The
cash consideration includes cash due to warrant and option holders, net of
cash received from the

                                      40
<PAGE>

                            PETROCORP INCORPORATED

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                       December 31, 2001, 2000 and 1999

exercise of Southern Mineral warrants and options. The totals include $3.4
million for 800,336 shares of Southern Mineral purchased by PetroCorp in open
market transactions prior to the merger.

   The acquisition of Southern Mineral was accounted for using the purchase
method of accounting as of June 1, 2001 because as of that date, the Company
had effective control, and the results of operations have been included since
that date. The aggregate purchase price was as follows (amounts in thousands):

<TABLE>
      <S>                                                               <C>
      Issuance of common stock (net of $380 registration costs)........ $38,618
      Net cash to Southern Mineral stockholders and warrant holders....  20,989
      Legal, professional and other costs..............................     424
      Assumed liabilities and debt and liabilities incurred............  28,661
                                                                        -------
      Total purchase consideration..................................... $88,692
                                                                        =======
</TABLE>

   The following unaudited pro forma information has been prepared assuming
Southern Mineral had been acquired as of the beginning of the period
presented. The pro forma information is presented for information purposes
only and is not necessarily indicative of what would have occurred if the
acquisition had been made as of that date. In addition, the pro forma
information is not intended to be a projection of future results and does not
reflect any efficiencies that may result from the integration of Southern
Mineral.

                       Pro Forma Information (Unaudited)
                     (In thousands, except per share data)
<TABLE>
<CAPTION>
                                                        Year Ended   Year Ended
                                                       December 31, December 31,
                                                           2001         2000
                                                       ------------ ------------
      <S>                                              <C>          <C>
      Revenues........................................   $65,487      $78,153
      Income before income taxes......................   $ 2,711      $28,690
      Net income......................................   $ 2,622      $16,385
      Earnings per common share--basic................   $  0.21      $  1.29
      Earnings per common share--diluted .............   $  0.20      $  1.28
</TABLE>

   The above pro forma data reflects $3,665 and $5,544, respectively, of
bankruptcy expenses and restructuring costs (primarily investment banker and
employee severance related costs) for Southern Mineral for the year ended
December 31, 2001 and 2000.


                                      41
<PAGE>

                            PETROCORP INCORPORATED

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                       December 31, 2001, 2000 and 1999


5. Property, Plant and Equipment

   Investments in property, plant and equipment were as follows at December
31, 2001 and 2000 (amounts in thousands):

<TABLE>
<CAPTION>
                                                           2001       2000
                                                         ---------  ---------
      <S>                                                <C>        <C>
      Oil and gas properties:
        Proved.......................................... $ 315,935  $ 226,813
        Unproved........................................     1,223      2,032
                                                         ---------  ---------
                                                           317,158    228,845
      Plant and related facilities......................     9,743      9,969
      Gas gathering facilities..........................     1,698      1,698
      Furniture, fixtures and equipment.................        95         --
                                                         ---------  ---------
                                                           328,694    240,512
      Less--accumulated depreciation, depletion,
       amortization and impairment......................  (200,242)  (169,576)
                                                         ---------  ---------
                                                         $ 128,452  $  70,936
                                                         =========  =========
</TABLE>

   Depreciation, depletion and amortization for all property, plant and
equipment for the years ended December 31, 2001, 2000 and 1999 was
$16,846,000, $9,471,000 and $9,906,000, respectively. Oil and gas property
depreciation, depletion and amortization for the years ended December 31,
2001, 2000 and 1999 was $15,529,000, $7,947,000 and $8,138,000 , respectively.
Depreciation, depletion and amortization per equivalent Mcf (using a Mcf-to-
barrel conversion factor of 6 to 1) for the years ended December 31, 2001,
2000 and 1999 was $1.38, $0.85 and $0.85, respectively, for U.S. operations
and $0.92, $0.61 and $0.50, respectively, for Canadian operations. The total
composite rates were $1.15, $0.74 and $0.69 for the years ended December 31,
2001, 2000 and 1999, respectively. During 2001 the Company also recorded a
ceiling test write-down of $15,400,000.

6. Long-Term Debt

   The Company's total long-term debt is as follows (amounts in thousands):

<TABLE>
<CAPTION>
                                                                2001     2000
                                                               -------  -------
      <S>                                                      <C>      <C>
      TD Bank Credit Agreement................................ $47,288  $28,500
      Nonrecourse Note Payable................................   1,659    2,686
      Less: Current portion...................................  (1,327)  (1,194)
                                                               -------  -------
      Total long-term debt.................................... $47,620  $29,992
                                                               =======  =======
</TABLE>

   Debt maturing subsequent to December 31, 2001 is as follows: $1,327,000 in
2002, and $47,620,000 in 2003.

 Bank Debt

   On June 26, 1997, the Company entered into a $50 million, five-year
revolving credit agreement with the Toronto-Dominion Bank (TD Bank), the
agent, and the Bank of Nova Scotia. The facility was amended in June 1998 and
July 1999 to extend the initial five-year term an additional year to July 1,
2003 with quarterly borrowing base amortization beginning September 30, 2001.

                                      42
<PAGE>

                            PETROCORP INCORPORATED

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                       December 31, 2001, 2000 and 1999


   In July 2000, the Company entered into a new $75 million revolving credit
agreement with the Toronto-Dominion Bank (TD Bank), the agent, and the Bank of
Nova Scotia. The term of the facility is through April 30, 2003 and the
initial borrowing base was set at $58 million. Borrowings can be funded by
either Eurodollar loans or Base Rate loans. The interest rate on the
borrowings is equal to an interest rate spread plus either the Eurodollar rate
or the Base Rate. The interest spread is determined from a sliding scale based
on the Company's borrowing base percentage utilization in effect from time to
time. The spread ranges from 1.25 to 2.25 on Eurodollar loans and .25 to 1.25
on Base Rate loans. At December 31, 2001, the weighted average interest rate
under this facility was approximately 4.1%.

   The $75 million revolving credit agreement prohibits the declaration and
payment of dividends on the common stock of the Company. Also, the debt
agreement requires the Company to maintain a minimum current ratio, a minimum
tangible net worth, and a minimum interest coverage ratio.

 Nonrecourse Notes Payable

   On December 12, 1991, the Company (through its Canadian subsidiary, PCC
Inc.) acquired an interest in certain oil and gas properties and related gas
processing facilities located in the Hanlan-Robb area in western Alberta,
Canada. The Company used the proceeds from the issuance of redeemable
preferred stock of PCC Inc. to partially fund the acquisition. The holders of
the preferred stock also separately and concurrently acquired an interest in
the same oil and gas properties as the Company.

   On August 9, 1994, PCC Inc. entered into agreements whereby PCC Inc.
redeemed the remaining shares of its redeemable preferred stock for
$7,034,000. Simultaneously, PCC Inc. issued $7,034,000 in nonrecourse long-
term notes payable (the Nonrecourse Notes Payable) to the previous holders of
the preferred stock with financial terms similar to the redeemable preferred
stock. Consistent with the redeemable preferred stock, the Nonrecourse Notes
Payable are denominated in Canadian dollars.

   In 2001, 2000 and 1999, the Company issued $311,000, $525,000 and $238,000
of additional notes, respectively, as provided under the provisions of the
agreements to finance the company's portion of plant capital additions.

   Interest accrues and is payable on a quarterly basis at a rate of 15% per
annum. In addition, redemptions are required to be made quarterly, based on a
fixed schedule through December 31, 2002. Interest and redemption payments are
made only to the extent there are sufficient cash proceeds from production and
sale of oil and gas reserves related to the interest in the Hanlan-Robb assets
acquired by the holders of the Nonrecourse Notes Payable. To the extent
interest and redemptions exceed such cash proceeds, the excess amount is
carried forward to the next quarter. At December 31, 2001 and 2000, unpaid
interest and redemptions totaled $394,000 and $334,000, respectively.

7. Hedging Activities

   To reduce the impact of fluctuations in the market prices of oil and
natural gas, the Company periodically utilizes hedging strategies such as
futures transactions or swaps to hedge the price of a portion of its future
oil and natural gas production. Results of these hedging transactions are
reflected in oil and natural gas sales in the month of the hedged production.

                                      43
<PAGE>

                            PETROCORP INCORPORATED

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                       December 31, 2001, 2000 and 1999


   In the first quarter of 2000, the Company entered into swap transactions in
an effort to lock in a portion of higher oil prices. These transactions
applied to approximately 50 percent of the Company's projected oil production
from April 2000 through December 2000, at prices ranging from $23.57 to $29.00
per barrel. In the second quarter of 2000, the Company entered into a no-cost
collar arrangement for a portion of its natural gas production by which
180,000 MMbtu for each of the months July through October 2000 were subject to
a $4.96 ceiling and a $3.50 floor per Mmbtu. Oil and gas revenue includes
$69,000 received and $1,166,000 paid in settlement of swap and collar
transactions through December 31, 2000. There were no hedges outstanding at
December 31, 2000.

   As part of PetroCorp's acquisition of Southern Mineral Corporation
("Southern Mineral"), the Company assumed crude oil and natural gas costless
collars with a fair value (liability) at date of acquisition of $821,000. The
estimated fair value of the derivative instruments, which fair values were
obtained from the counter-parties, held by the Company at December 31, 2001
were an asset of $644,000 (included in other current assets) related to the
oil and gas hedges and a liability of $314,000 (included in other liabilities)
related to the interest rate swap agreement. The ineffective portion of these
hedges was not material as of December 31, 2001. Hedging transactions for the
year ended December 31, 2001 increased oil and gas revenues by $270,000
(reclassified from comprehensive income).

   The Company offsets any gain or loss on the swap and collars contract with
the realized prices for its production. While the swaps and collars reduce the
Company's exposure to declines in the market price of natural gas and oil,
this also limits the Company's gains from increases in the market price.

   As a result of the merger with Southern Mineral, the Company also assumed
an interest rate swap position that was originally intended to hedge the
variability of interest expense associated with Southern Mineral's variable
rate Canadian debt. Under the swap agreement, the Company receives a floating
rate of the Canadian prime rate and pays a fixed rate of 5.96% on a notional
amount of Canadian $15 million. The interest rate swap did not qualify for
hedge accounting. The Company has recorded the swap's fair value of $192,000
as a liability at the date of the merger.

                                      44
<PAGE>

                             PETROCORP INCORPORATED

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                        December 31, 2001, 2000 and 1999


8. Income Taxes

   The components of income (loss) before income taxes for the years ended
December 31, 2001, 2000 and 1999 consisted of the following (amounts in
thousands):

<TABLE>
<CAPTION>
                                                    2001     2000       1999
                                                   -------  -------    -------
      <S>                                          <C>      <C>        <C>
      United States operations.................... $(9,941) $ 9,834    $(4,191)
      Canadian operations.........................  11,707   13,335      3,031
                                                   -------  -------    -------
                                                   $ 1,766  $23,169(A) $(1,160)
                                                   =======  =======    =======
</TABLE>

   The provision (benefit) for income taxes consists of the following (amounts
in thousands):

<TABLE>
<CAPTION>
                                                     2001     2000       1999
                                                    -------  -------    -------
      <S>                                           <C>      <C>        <C>
      Deferred:
        Federal.................................... $(4,448) $ 3,488    $(1,090)
        State......................................    (321)     317        (65)
        Canadian...................................  (1,063)     807        201
                                                    -------  -------    -------
                                                     (5,832)   4,612       (954)
                                                    =======  =======    =======
      Current:
        Federal....................................     110       --         --
        State......................................      47       --         --
        Canadian...................................   5,395    5,497         --
                                                    -------  -------    -------
                                                      5,552    5,497         --
                                                    -------  -------    -------
                                                    $  (280) $10,109(A) $  (954)
                                                    =======  =======    =======
</TABLE>
--------
(A) Excludes extraordinary loss of $385 and related taxes of $143.

                                       45
<PAGE>

                            PETROCORP INCORPORATED

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                       December 31, 2001, 2000 and 1999


   A reconciliation of the Company's United States income tax provision
(benefit) computed by applying the statutory United States federal income tax
rate to the Company's income (loss) before income taxes and extraordinary loss
for the years ended December 31, 2001, 2000, and 1999 is presented in the
following table (amounts in thousands):

<TABLE>
<CAPTION>
                                                     2001     2000     1999
                                                    -------  -------  -------
      <S>                                           <C>      <C>      <C>
      United States federal income taxes (benefit)
       at statutory rate of 35%.................... $   618  $ 8,109  $  (406)
      Increases (reductions) resulting from:
        Canadian earnings not subject to United
         States taxes..............................  (4,097)  (4,667)  (1,061)
        Canadian income taxes......................   4,332    6,304      201
        Statutory depletion........................  (1,079)      --       --
        State income taxes.........................    (178)     206      (65)
        Other......................................     124      157      377
                                                    -------  -------  -------
                                                    $ (280)  $10,109  $  (954)
                                                    =======  =======  =======
</TABLE>

   Deferred tax assets and liabilities consist of the following at December
31, 2001 and 2000 (amounts in thousands):

<TABLE>
<CAPTION>
                                                              2001      2000
                                                            --------  --------
      <S>                                                   <C>       <C>
      Deferred tax assets:
        Depletion and net operating loss carryforward--
         U.S............................................... $ 23,542  $ 15,404
        Net operating loss carryforward--Canada............      824       633
        Derivative liability...............................      134        --
                                                            --------  --------
      Gross deferred tax asset.............................   24,500    16,037
                                                            --------  --------
      Deferred tax liabilities:
        Excess of basis in property, plant and equipment
         for financial reporting purposes over the tax
         basis--U.S........................................   (5,238)   (5,150)
        Excess of basis in property, plant and equipment
         for financial reporting purposes over the tax
         basis--Canada.....................................  (14,662)   (6,825)
        Derivative asset...................................     (247)       --
                                                            --------  --------
      Gross deferred tax liability.........................  (20,147)  (11,975)
                                                            --------  --------
                                                            $  4,353  $  4,062
                                                            ========  ========
</TABLE>

   As of December 31, 2001, the Company has U.S. net operating loss (NOL)
carryforwards of $57,265,000 and $59,201,000 for regular tax and alternative
minimum tax purposes, respectively. Regular tax NOL carryforwards and
alternative minimum tax NOL carryforwards begin to expire in 2009.
Additionally, statutory depletion carryforwards of $7,322,000 are available at
December 31, 2001.

   Realization of the deferred tax asset is dependent on generating sufficient
taxable income prior to expiration of loss carryforwards. Although realization
is not assured, management believes it is more likely than not that the
deferred tax asset will be realized. The amount of the deferred tax asset
considered realizable, however, could be reduced in the near term if estimates
of future taxable income during the carryforward period are reduced.
Additionally, certain future changes in the Company's shareholders may impose
restrictions under Section 382 of the Internal Revenue Code on the annual
utilization of its net operating loss carryforwards.

                                      46
<PAGE>

                            PETROCORP INCORPORATED

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                       December 31, 2001, 2000 and 1999


   The provision for Canadian income taxes differs from the amount of income
tax determined by applying the Canadian statutory income tax rate to pretax
Canadian income as a result of the following (amounts in thousands):

<TABLE>
<CAPTION>
                                                      Years ended December
                                                               31,
                                                     -------------------------
                                                      2001     2000     1999
                                                     -------  -------  -------
      <S>                                            <C>      <C>      <C>
      Tax computed at statutory rate of 44.62%
       (42.62% for 2001)...........................  $ 4,990  $ 5,950  $ 1,352
      Nondeductible crown royalties, net of royalty
       credits.....................................    5,822    4,411    1,515
      Resource allowance...........................   (5,405)  (5,299)  (2,666)
      Revenue Canada audit adjustments.............   (1,075)   1,242       --
                                                     -------  -------  -------
                                                     $ 4,332  $ 6,304  $   201
                                                     =======  =======  =======
</TABLE>

9. Stock Option and Other Employee Benefit Plans

   In 1992, the Company established the 1992 PetroCorp Stock Option Plan (the
Option Plan). The Option Plan allows up to 957,357 option shares to be
granted. The following table summarizes these options:

<TABLE>
<CAPTION>
                                                                Weighted Average
                                                      Options    Exercise Price
                                                      --------  ----------------
      <S>                                             <C>       <C>
      Outstanding at December 31, 1998...............  719,500       $ 7.87
        Granted......................................       --           --
        Forfeited....................................  (20,000)      $ 6.38
        Exercised....................................  (27,000)      $ 5.00
                                                      --------
      Outstanding at December 31, 1999...............  672,500       $ 8.04
        Granted......................................       --           --
        Forfeited....................................       --           --
        Exercised....................................  (20,700)      $ 6.38
                                                      --------
      Outstanding at December 31, 2000...............  651,800       $ 8.09
        Granted......................................       --           --
        Forfeited.................................... (162,000)      $10.00
        Exercised.................................... (101,300)      $ 6.55
                                                      --------
      Outstanding at December 31, 2001...............  388,500       $ 7.69
                                                      ========
</TABLE>

   Of the 388,500 outstanding options under the Option Plan at December 31,
2001, 121,500 options with an exercise price of $5.00, 80,000 options with an
exercise price of $6.38 and 187,000 options with an exercise price of $10 had
weighted average contractual lives of 0.75 years, 4.1 years and 0.75 years,
respectively. All of these options are exercisable as of December 31, 2001.

                                      47
<PAGE>

                            PETROCORP INCORPORATED

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                       December 31, 2001, 2000 and 1999


   In 1997, the Company established the 1997 PetroCorp Non-Employee Director
Stock Option Plan (the Director Option Plan) for the benefit of the Company's
Board of Directors. This plan allows up to 75,000 option shares to be granted.
The Director Options were fully vested and exercisable at the date of grant.
The following table summarizes these options:

<TABLE>
<CAPTION>
                                                                Weighted Average
                                                       Options   Exercise Price
                                                       -------  ----------------
      <S>                                              <C>      <C>
      Outstanding at December 31, 1998................  31,000       $8.55
        Granted.......................................   6,000       $6.75
        Forfeited.....................................      --          --
        Exercised.....................................      --          --
                                                       -------
      Outstanding at December 31, 1999................  37,000       $8.26
        Granted.......................................      --          --
        Forfeited.....................................      --          --
        Exercised.....................................      --          --
                                                       -------
      Outstanding at December 31, 2000................  37,000       $8.26
        Granted.......................................      --          --
        Forfeited..................................... (14,000)      $8.30
        Exercised.....................................      --          --
                                                       -------
      Outstanding at December 31, 2001................  23,000       $8.23
                                                       =======
</TABLE>

   As of December 31, 2001, the weighted average remaining contractual life of
the outstanding options under the Director Option Plan was 6.0 years and the
exercise prices ranged from $6.75 to $8.63.

   In 2000, the Company established the 2000 Stock Option Plan for the benefit
of employees and the Company's Board of Directors. Employee options vest one
year from date of grant and director options vest six months from the date of
grant. This plan allows up to 600,000 option shares to be granted. The
following table summarizes these options:

<TABLE>
<CAPTION>
                                                                Weighted Average
                                                       Options   Exercise Price
                                                       -------  ----------------
      <S>                                              <C>      <C>
      Outstanding at December 31, 1999................      --          --
        Granted....................................... 106,650       $6.34
        Forfeited.....................................      --          --
        Exercised.....................................      --          --
                                                       -------
      Outstanding at December 31, 2000................ 106,650       $6.34
        Granted....................................... 163,000       $9.67
        Forfeited.....................................  (6,500)      $9.15
        Exercised.....................................  (6,500)      $6.13
                                                       -------
      Outstanding at December 31, 2001................ 256,650       $8.39
                                                       =======
</TABLE>

   As of December 31, 2001, the weighted average remaining contractual life of
the outstanding options under the 2000 Stock Option Plan was 8.8 years. Of the
outstanding options, 154,150 were exercisable at year end with an average
remaining contractual life of 8.6 years. At December 31, 2001, exercise prices
ranged from $6.13 to $9.75.

                                      48
<PAGE>

                            PETROCORP INCORPORATED

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                       December 31, 2001, 2000 and 1999


   As part of the merger with Southern Mineral, PetroCorp assumed all stock
options under the various plans of Southern Mineral. Under the terms of these
plans, options equivalent to 330,393 shares of PetroCorp stock have been
authorized. No additional grants are anticipated. All outstanding options were
vested at the date of the merger. The following table summarizes these
options:

<TABLE>
<CAPTION>
                                                                        Weighted
                                                                        Average
                                                                        Exercise
                                                               Options   Price
                                                               -------  --------
      <S>                                                      <C>      <C>
      Outstanding at December 31, 2000........................      --       --
        Granted............................................... 179,268   $18.70
        Forfeited............................................. (44,887)  $14.47
        Exercised.............................................  (9,420)  $ 5.31
                                                               -------
      Outstanding at December 31, 2001........................ 124,961   $21.01
                                                               =======
</TABLE>

   As of December 31, 2001, all outstanding options were exercisable and all
will expire in 2002. At December 31, 2001, exercise prices ranged from $10.62
to $71.87.

   Stock options under all three plans expire ten years from the date of grant
and the exercise price equals market value on the grant date.

   The Company adopted SFAS No. 123, "Accounting for Stock Based
Compensation," effective July 1, 1996. While SFAS No. 123 encourages entities
to adopt the fair value based method of accounting for their stock-based
compensation plans, the Company has elected to continue to utilize the
intrinsic value method under Accounting Principles Board (APB) Opinion No. 25,
"Accounting for Stock Issued to Employees." Compensation expense has been
recognized for these stock-based compensation plans for any grants to
individuals who do not meet the definition of employee. Had compensation cost
for the 2000 Stock Option Plan and the Director Option Plan been determined
based upon the fair value at the grant date for awards under the plans,
consistent with the methodology prescribed under SFAS No. 123, the Company's
2001 and 2000 net income and 1999 net loss and earnings/loss per share would
have been reduced/increased by approximately $383,000, $330,000 and $17,000,
or $0.03, $0.04 and nil per share, respectively. The fair value of the options
granted during 2001, 2000 and 1999 were $751,000, $432,000 and $27,000,
respectively, on the dates of grants using the Black-Scholes option-pricing
model with the following assumptions:

<TABLE>
<CAPTION>
                                                         2001      2000    1999
                                                       --------- --------- ----
      <S>                                              <C>       <C>       <C>
      Weighted average life, in years.................    10        10      10
      Risk-Free interest rate......................... 5.1%-5.2% 6.0%-6.5% 6.1%
      Expected Volatility.............................    40%       41%    46%
      Expected Dividend Rate..........................   None      None    None
</TABLE>

   Effective January 1, 1993, the Company established a savings plan, which is
available to eligible employees and qualifies as a deferred compensation plan
under Section 401(k) of the Internal Revenue Code. The Company matches
employee contributions for an amount up to 6% of each employee's salary. The
Company's contributions to the plan, which are charged to expense, totaled
nil, $100,000 and $198,000 in 2001, 2000 and 1999, respectively.

                                      49
<PAGE>

                            PETROCORP INCORPORATED

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                       December 31, 2001, 2000 and 1999


10. Earnings Per Share

   The following is a reconciliation of the numerators and denominators of the
basic and diluted per share computations for the periods presented (in
thousands, except per share amounts).

<TABLE>
<CAPTION>
                                                    Per Share Amounts
                                            ----------------------------------
                                             Net Income
                                            (Loss) Before                Net
                                            Extraordinary Extraordianry Income
                            Income   Shares     Item          Item      (Loss)
                            -------  ------ ------------- ------------- ------
<S>                         <C>      <C>    <C>           <C>           <C>
Year ended December 31,
 2001
  Basic EPS:
    Net income............. $ 2,046  10,975    $ 0.19        $   --     $ 0.19
  Effect of dilutive
   securities:
    Options................      --     144     (0.01)           --      (0.01)
                            -------  ------    ------        ------     ------
  Diluted EPS:
    Net income............. $ 2,046  11,119    $ 0.18        $   --     $ 0.18
                            =======  ======    ======        ======     ======
Year ended December 31,
 2000
  Basic EPS:
    Net income(A).......... $12,818   8,692    $ 1.50        $(0.03)    $ 1.47
  Effect of dilutive
   securities:
    Options................      --      94     (0.01)           --      (0.01)
                            -------  ------    ------        ------     ------
  Diluted EPS:
    Net income(A).......... $12,818   8,786    $ 1.49        $(0.03)    $ 1.46
                            =======  ======    ======        ======     ======
Year ended December 31,
 1999
  Basic EPS:
    Net loss............... $  (206)  8,658    $(0.02)       $   --     $(0.02)
  Effect of dilutive
   securities:
    Options................      --      --        --            --         --
                            -------  ------    ------        ------     ------
  Diluted EPS:
    Net loss............... $  (206)  8,658    $(0.02)       $   --     $(0.02)
                            =======  ======    ======        ======     ======
</TABLE>
--------
(A) Net of extraordinary loss of $242.

   The 2001 and 2000 net income per share and the 1999 net loss per share
amounts do not include the effect of potentially dilutive securities of
469,000, 395,000 and 709,500, respectively, as the impact of these outstanding
options was antidilutive.

                                      50
<PAGE>

                            PETROCORP INCORPORATED

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                       December 31, 2001, 2000 and 1999


11. Geographic Area Information

   The principal business of the Company is oil and gas, which consists of the
exploration, development, acquisition, exploitation and operation of oil and
gas properties and the production and sale of crude oil and natural gas in
North America. Pertinent information with respect to the Company's oil and gas
business is presented in the following table (amounts in thousands):

<TABLE>
<CAPTION>
                                         United            General
                                         States   Canada  Corporate     Total
                                         -------  ------- ---------    --------
<S>                                      <C>      <C>     <C>          <C>
2001:
  Revenues.............................. $25,169  $26,105  $    --     $ 51,274
  Income (loss) from operations.........  (8,722)  13,170   (2,259)       2,189
  Depreciation, depletion, amorization
   and impairment.......................  25,016    7,328       --       32,344
  Capital expenditures..................  55,432   38,284       --       93,716
  Long-lived assets at December 31......  67,068   63,952      131      131,151
2000:
  Revenues.............................. $23,588  $20,985  $    --     $ 44,573
  Income (loss) from operations.........  12,353   14,402   (1,084)(A)   25,671
  Depreciation, depletion and
   amortization.........................   5,178    4,293       --        9,471
  Capital expenditures..................   1,730    6,459       --        8,189
  Long-lived assets at December 31......  34,005   36,931      242       71,178
1999:
  Revenues.............................. $15,565  $11,561  $    --     $ 27,126
  Income (loss) from operations.........   5,045    5,607   (8,400)(B)    2,252
  Depreciation, depletion and
   amortization.........................   5,746    3,714      446        9,906
  Capital expenditures..................   1,043    2,212       --        3,255
  Long-lived assets at December 31......  37,600   36,106      107       73,813
</TABLE>
--------
(A) Net of $445 restructuring cost credits.
(B) Includes $3,643 of restructuring costs.

   The following table reflects purchasers which accounted for more than 10%
of the Company's oil and gas revenues:

<TABLE>
<CAPTION>
                                                                  2001  2000  1999
                                                                  ----  ----  ----
      <S>                                                         <C>   <C>   <C>
      Pan-Alberta Gas Ltd........................................  22%   19%   18%
      EOTT Energy Operating Limited Partnership..................  --    --    11%
      Engage Energy LP...........................................  32%   27%   17%
</TABLE>

   During 1999 and prior, the majority of the Company's Canadian gas was
dedicated under long-term contracts to Pan-Alberta Gas Ltd., a major Canadian
aggregator. However, as part of a legal settlement effective December 31,
1998, approximately 50% of PetroCorp's dedicated gas volumes have been
released from the Pan-Alberta contracts. These released volumes are now sold
on the spot market at prevailing prices. The Company does not believe the loss
of any purchaser would have a material adverse effect on its financial
position since the Company believes alternative sales arrangements could be
made on relatively comparable terms.

                                      51
<PAGE>

                            PETROCORP INCORPORATED

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                       December 31, 2001, 2000 and 1999


12. Common Stock Repurchases

   On September 14, 2001, the Company announced that the Board of Directors
authorized the purchase of up to 1,000,000 shares of the Company's common
stock. Through December 31, 2001, 264,607 shares have been purchased at a cost
of $2,350,000, which shares are held in treasury.

13. Commitments and Contingencies

   The Company has entered into operating lease agreements with noncancellable
terms in excess of one year for office space. Future minimum lease payments
are $376,000 and $54,000 for the years ending December 31, 2002 and 2003,
respectively with no payments after that time. Future minimum sublease income
with noncancellable terms in excess of one year for office space are $159,000
and $34,000 for the years ending December 31, 2002 and 2003. Total rental
expense for office space for the years ended December 31, 2001, 2000 and 1999
was $140,000, $111,000 and $583,000, respectively.

   On February 13, 2002, R.A. Mackie & Co., L.P., Millenco, L.P. and Wein
Securities Corp, as plaintiffs, filed a lawsuit against PetroCorp in New York
Supreme Court (Index No. 02-600589). In this action certain former holders of
warrants of Southern Mineral Corporation allege that the provisions made for
such warrants in connection with the merger of Southern Mineral Corporation
into PetroCorp Acquisition Corporation, a wholly-owned subsidiary of PetroCorp
Incorporated, were inadequate. The plaintiffs seek $5,000,000. Based on
consultation with legal counsel, the Company is of the opinion the action is
without merit.

   There are other claims and actions pending against the Company. In the
opinion of management, the amounts, if any, which may be awarded in connection
with any of these claims and actions would not be material to the Company's
consolidated financial position or results of operations.

14. Related Party Transactions

   The Company has engaged an engineering consulting company to procure
certain services and equipment pertaining to its Canadian operations. The
consulting company solicits bids from various vendors in order to obtain
competitive pricing. During 2001, 2000 and 1999, the consulting company
procured $3,000, nil and $45,000 from an equipment supplier partly owned by a
director of the Company's Canadian subsidiaries who is a relative of the
Company's previous Chief Executive Officer.

   The Company is a joint-interest owner in a project operated by Kaiser-
Francis Oil Company, a shareholder. During 2001, 2000 and 1999, the Company
remitted $63,000, $154,000 and $95,000, respectively, to Kaiser-Francis as
payment of the Company's share of the joint operation. During 2001, the
Company remitted $2,176,000 and $888,000 to Kaiser-Francis for management fees
and cost reimbursements, respectively, under the Management Agreement (see
Note 2). Amounts payable to Kaiser-Francis at December 31, 2001 and 2000 were
$272,000 and $22,000, respectively.


                                      52
<PAGE>

                            PETROCORP INCORPORATED

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                       December 31, 2001, 2000 and 1999

15. Oil and Gas Reserves and Related Financial Data

 Capitalized Costs Related to Oil and Gas Producing Activities

   The following table presents total capitalized costs of proved and unproved
properties and accumulated depreciation, depletion and amortization related to
petroleum producing operations (amounts in thousands):

<TABLE>
<CAPTION>
                                                 U.S.      Canada     Total
                                               ---------  --------  ---------
   <S>                                         <C>        <C>       <C>
   2001:
     Proved properties........................ $ 233,204  $ 82,731  $ 315,935
     Unproved properties......................       263       960      1,223
                                               ---------  --------  ---------
                                                 233,467    83,691    317,158
     Accumulated depreciation, depletion and
      amortization............................  (168,989)  (21,244)  (190,233)
                                               =========  ========  =========
                                               $  64,478  $ 62,447  $ 126,925
                                               =========  ========  =========
   2000:
     Proved properties........................ $ 176,834  $ 49,979  $ 226,813
     Unproved properties......................     1,223       809      2,032
                                               ---------  --------  ---------
                                                 178,057    50,788    228,845
     Accumulated depreciation, depletion and
      amortization............................  (144,105)  (16,308)  (160,413)
                                               ---------  --------  ---------
                                               $  33,952  $ 34,480  $  68,432
                                               =========  ========  =========
   1999:
     Proved properties........................ $ 171,931  $ 45,060  $ 216,991
     Unproved properties......................     4,599     1,555      6,154
                                               ---------  --------  ---------
                                                 176,530    46,615    223,145
     Accumulated depreciation, depletion and
      amortization............................  (139,323)  (13,670)  (152,993)
                                               ---------  --------  ---------
                                               $  37,207  $ 32,945  $  70,152
                                               =========  ========  =========
</TABLE>

   Of the unproved properties capitalized cost at December 31, 2001,
approximately $96,000 and $349,000 were incurred in 2001 and 2000,
respectively. The Company anticipates evaluating these properties during
subsequent years.

                                      53
<PAGE>

                            PETROCORP INCORPORATED

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                       December 31, 2001, 2000 and 1999


 Costs Incurred in Oil and Gas Producing Activities

   Presented below are costs incurred in oil and gas property acquisition,
exploration and development activities (amounts in thousands):

<TABLE>
<CAPTION>
                                                         U.S.   Canada   Total
                                                        ------- ------- -------
   <S>                                                  <C>     <C>     <C>
   2001:
     Acquisition of properties:
       Proved properties............................... $42,608 $33,476 $76,084
       Unproved properties.............................     678      --     678
     Exploration costs.................................   2,003   1,166   3,169
     Development costs(A)..............................  10,121   3,203  13,324
                                                        ------- ------- -------
       Total........................................... $55,410 $37,845 $93,255
                                                        ======= ======= =======
   2000:
     Acquisition of properties:
       Proved properties............................... $   104 $   126 $   230
       Unproved properties.............................      80     269     349
     Exploration costs.................................      --     166     166
     Development costs(A)..............................   1,553   5,365   6,918
                                                        ------- ------- -------
       Total........................................... $ 1,737 $ 5,926 $ 7,663
                                                        ======= ======= =======
   1999:
     Acquisition of properties:
       Proved properties............................... $   150 $   230 $   380
       Unproved properties.............................      90       9      99
     Exploration costs.................................      27     204     231
     Development costs.................................     776   1,603   2,379
                                                        ------- ------- -------
       Total........................................... $ 1,043 $ 2,046 $ 3,089
                                                        ======= ======= =======
</TABLE>
--------
(A) Includes approximately $42 and $600 of costs incurred in 2001 and 2000,
    respectively, for development of properties previously classified as
    proved undeveloped properties for the years 2000 and 1999 respectively.

   Included in the above amounts for the years ended December 31, 2001, 2000
and 1999 were nil, nil, and $1,188, respectively, of capitalized internal
costs related to property acquisition, exploration and development.

                                      54
<PAGE>

                             PETROCORP INCORPORATED

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                        December 31, 2001, 2000 and 1999


 Results of Operations From Oil and Gas Producing Activities (unaudited)

   The results of operations from oil and gas producing activities, which do
not include revenues associated with the production and sale of sulfur, are as
follows (amounts in thousands):

<TABLE>
<CAPTION>
                                                     U.S.    Canada    Total
                                                   --------  -------  --------
   <S>                                             <C>       <C>      <C>
   2001:
     Revenues..................................... $ 24,944  $23,114  $ 48,058
     Production costs.............................   (8,705)  (4,292)  (12,997)
     Depreciation, depletion, amortization and
      impairment..................................  (24,884)  (6,045)  (30,929)
     Income tax benefit (expense).................   (2,500)  (5,863)   (8,363)
                                                   --------  -------  --------
     Results of operations from petroleum
      producing activities (excluding corporate
      overhead and interest costs)................ $(11,145) $ 6,914  $ (4,231)
                                                   ========  =======  ========
   2000:
     Revenues..................................... $ 23,481  $18,783  $ 42,264
     Production costs.............................   (5,813)  (2,225)   (8,038)
     Depreciation, depletion and amortization.....   (4,782)  (3,165)   (7,947)
     Income tax benefit (expense).................   (4,728)  (5,078)   (9,806)
                                                   --------  -------  --------
     Results of operations from petroleum
      producing activities (excluding corporate
      overhead and interest costs)................ $  8,158  $ 8,315  $ 16,473
                                                   ========  =======  ========
   1999:
     Revenues..................................... $ 15,506  $ 9,656  $ 25,162
     Production costs.............................   (4,555)  (2,178)   (6,733)
     Depreciation, depletion and amortization.....   (5,410)  (2,728)   (8,138)
     Income tax benefit (expense).................   (2,050)    (973)   (3,023)
                                                   --------  -------  --------
     Results of operations from petroleum
      producing activities (excluding corporate
      overhead and interest costs)................ $  3,491  $ 3,777  $  7,268
                                                   ========  =======  ========
</TABLE>


                                       55
<PAGE>

                            PETROCORP INCORPORATED

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                       December 31, 2001, 2000 and 1999

 Reserve Quantities (unauditied)

   Estimates of proved reserves and the related standardized measure of
discounted future net cash flow information are based on the reports of
independent petroleum engineers for 2000 and 1999 and reserve evaluations
performed by the Company's engineer in 2001 and reviewed by independent
petroleum engineers.

   The Company's estimates of its proved reserves and proved developed
reserves of oil and gas as of December 31, 2001, 2000 and 1999 and the changes
in its proved reserves are as follows:

<TABLE>
<CAPTION>
                                     U.S.           Canada          Total
                                --------------  --------------  --------------
                                  Oil    Gas      Oil    Gas      Oil    Gas
                                (MBbls) (MMcf)  (MBbls) (MMcf)  (MBbls) (MMcf)
                                ------- ------  ------- ------  ------- ------
<S>                             <C>     <C>     <C>     <C>     <C>     <C>
2001:
 Proved reserves:
   Beginning of year...........  3,109  22,709   1,101  52,550   4,210  75,259
   Production..................   (396) (4,498)   (203) (5,376)   (599) (9,874)
   Purchase of minerals-in-
    place......................  2,190  19,722   1,585  12,086   3,775  31,808
   Extensions and discoveries..     25     867      --   1,089      25   1,956
   Improved recoveries.........     --      --      --      --      --      --
   Sales of minerals-in-place..     --      --      --      --      --      --
   Revision to previous
    estimates..................   (997)  2,584      35  (1,758)   (962)    826
                                 -----  ------   -----  ------   -----  ------
   End of year.................  3,931  41,384   2,518  58,591   6,449  99,975
                                 =====  ======   =====  ======   =====  ======
 Proved developed reserves:
   Beginning of year...........  2,888  20,551   1,068  46,624   3,956  67,175
                                 =====  ======   =====  ======   =====  ======
   End of year.................  3,350  38,806   2,242  50,876   5,592  89,682
                                 =====  ======   =====  ======   =====  ======
2000:
 Proved reserves:
   Beginning of year...........  3,261  20,950   1,320  55,409   4,581  76,359
   Production..................   (294) (3,850)   (110) (4,519)   (404) (8,369)
   Purchase of minerals-in-
    place......................      8       1      --     213       8     214
   Extensions and discoveries..    155   1,314     100   4,049     255   5,363
   Improved recoveries.........     --      --      --      --      --      --
   Sales of minerals-in-place..     --    (213)     --      --      --    (213)
   Revision to previous
    estimates..................    (21)  4,507    (209) (2,602)   (230)  1,905
                                 -----  ------   -----  ------   -----  ------
   End of year.................  3,109  22,709   1,101  52,550   4,210  75,259
                                 =====  ======   =====  ======   =====  ======
 Proved developed reserves:
   Beginning of year...........  3,180  18,906   1,187  47,026   4,367  65,932
                                 =====  ======   =====  ======   =====  ======
   End of year.................  2,888  20,551   1,068  46,624   3,956  67,175
                                 =====  ======   =====  ======   =====  ======
1999:
 Proved reserves:
   Beginning of year...........  2,578  21,970   1,412  57,422   3,990  79,392
   Production..................   (324) (4,421)   (138) (4,660)   (462) (9,081)
   Purchase of minerals-in-
    place......................     --     148      --   1,098      --   1,246
   Extensions and discoveries..     --      --       6   1,066       6   1,066
   Improved recoveries.........    605      91      --      --     605      91
   Sales of minerals-in-place..     --      --      --      --      --      --
   Revision to previous
    estimates..................    402   3,162      40     483     442   3,645
                                 -----  ------   -----  ------   -----  ------
   End of year.................  3,261  20,950   1,320  55,409   4,581  76,359
                                 =====  ======   =====  ======   =====  ======
 Proved developed reserves:
   Beginning of year...........  2,499  19,454   1,081  47,460   3,580  66,914
                                 =====  ======   =====  ======   =====  ======
   End of year.................  3,180  18,906   1,187  47,026   4,367  65,932
                                 =====  ======   =====  ======   =====  ======
</TABLE>


                                      56
<PAGE>

                             PETROCORP INCORPORATED

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                        December 31, 2001, 2000 and 1999


 Standardized Measure of Discounted Future Net Cash Flows (unaudited)

   The standardized measure of discounted future net cash flows was calculated
by applying current prices to estimated future production, less future
expenditures (based on current costs) to be incurred in developing and
producing such proved reserves and the estimated effect of future income taxes
based on the current tax law. The resulting future net cash flows were
discounted using a rate of 10% per annum.

   The standardized measure of discounted future net cash flow amounts
contained in the following tabulation do not purport to represent the fair
market value of oil and gas properties. No value has been given to unproved
properties. There are significant uncertainties inherent in estimating
quantities of proved reserves and in projecting rates of production and the
timing and amount of future costs. Future realization of oil and gas prices
over the remaining reserve lives may vary significantly from current prices. In
addition, the method of valuation utilized, based on current prices and costs
and the use of a 10% discount rate, is not necessarily appropriate for
determining fair value. The average prices used were based on the adjusted cash
spot price for natural gas and oil at December 31. At December 31, 2001, there
were crude oil and natural gas collar hedges outstanding with a fair value of
$644,000.

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

<TABLE>
<CAPTION>
                                                      U.S.    Canada   Total
                                                    -------- -------- --------
<S>                                                 <C>      <C>      <C>
2001:
  Future gross revenues............................ $169,025 $175,058 $344,083
  Less--future costs:
    Production.....................................   58,768   47,806  106,574
    Development(A).................................   10,850    4,358   15,208
                                                    -------- -------- --------
  Future net cash flows before income taxes........   99,407  122,894  222,301
  Less--10% annual discount for estimated timing of
   cash flows......................................   39,836   49,229   89,065
                                                    -------- -------- --------
  Present value of future net cash flows before
   income tax......................................   59,571   73,665  133,236
  Less--present value of future income taxes.......      752   28,130   28,882
                                                    -------- -------- --------
  Standardized measure of discounted future net
   cash flows...................................... $ 58,819 $ 45,535 $104,354
                                                    ======== ======== ========
(A) $ 11,511 of development costs are for proved
 undeveloped properties

2000:
  Future gross revenues............................ $313,677 $501,760 $815,437
  Less--future costs:
    Production.....................................   55,534   31,530   87,064
    Development (A)................................    2,457    2,979    5,436
                                                    -------- -------- --------
  Future net cash flows before income taxes........  255,686  467,251  722,937
  Less--10% annual discount for estimated timing of
   cash flows......................................  103,563  209,119  312,682
                                                    -------- -------- --------
  Present value of future net cash flows before
   income tax......................................  152,123  258,132  410,255
  Less--present value of future income taxes.......   42,860  110,860  153,720
                                                    -------- -------- --------
  Standardized measure of discounted future net
   cash flows...................................... $109,263 $147,272 $256,535
                                                    ======== ======== ========
(A) $3,232 of development costs are for proved
 undeveloped properties
</TABLE>

                                       57
<PAGE>

                             PETROCORP INCORPORATED

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                        December 31, 2001, 2000 and 1999

<TABLE>
<CAPTION>
                                                       U.S.    Canada   Total
                                                     -------- -------- --------
<S>                                                  <C>      <C>      <C>
1999:
  Future gross revenues............................. $128,792 $129,892 $258,684
  Less--future costs:
    Production......................................   35,640   23,544   59,184
    Development.....................................    1,799    3,530    5,329
                                                     -------- -------- --------
  Future net cash flows before income taxes.........   91,353  102,818  194,171
  Less--10% annual discount for estimated timing of
   cash flows.......................................   30,671   44,753   75,424
                                                     -------- -------- --------
  Present value of future net cash flows before
   income tax.......................................   60,682   58,065  118,747
  Less--present value of future income taxes........    4,276   20,711   24,987
                                                     -------- -------- --------
  Standardized measure of discounted future net cash
   flows............................................ $ 56,406 $ 37,354 $ 93,760
                                                     ======== ======== ========
</TABLE>

                                       58
<PAGE>

                             PETROCORP INCORPORATED

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                        December 31, 2001, 2000 and 1999


   The following table summarizes the principal sources of change in the
standardized measure of discounted future net cash flows (amounts in
thousands):

<TABLE>
<CAPTION>
                                                    U.S.     Canada    Total
                                                  --------  --------  --------
<S>                                               <C>       <C>       <C>
2001:
  Standardized measure--beginning of period...... $109,263  $147,272  $256,535
  Sales of oil and gas produced, net of
   production costs..............................  (16,239)  (18,822)  (35,061)
  Purchases of minerals-in-place.................   27,385    23,450    50,835
  Extensions, discoveries and improved recovery..    1,197     1,612     2,809
  Sales of minerals-in-place.....................       --        --        --
  Net changes in prices and productions costs.... (114,680) (240,848) (355,528)
  Changes in estimated future development costs..  (11,036)   (2,994)  (14,030)
  Development costs incurred.....................   10,121     3,203    13,324
  Revisions to previous quantity estimates.......   (3,103)   (1,686)   (4,789)
  Accretion of discount..........................   15,213    25,813    41,026
  Changes in timing of production and other......   (1,410)   25,805    24,395
  Net changes in income taxes....................   42,108    82,730   124,838
                                                  --------  --------  --------
  Standardized measure--end of period............ $ 58,819  $ 45,535  $104,354
                                                  ========  ========  ========
2000:
  Standardized measure--beginning of period...... $ 56,406  $ 37,354  $ 93,760
  Sales of oil and gas produced, net of
   production costs..............................  (17,668)  (16,558)  (34,226)
  Purchases of minerals-in-place.................       23        75        98
  Extensions, discoveries and improved recovery..    8,502    18,626    27,128
  Sales of minerals-in-place.....................     (108)       --      (108)
  Net changes in prices and productions costs....   94,155   219,553   313,708
  Development costs incurred.....................      238     2,705     2,943
  Revisions to previous quantity estimates.......   16,130   (18,563)   (2,433)
  Accretion of discount..........................    6,068     5,807    11,875
  Changes in timing of production and other......  (15,899)  (11,579)  (27,478)
  Net changes in income taxes....................  (38,584)  (90,148) (128,732)
                                                  --------  --------  --------
  Standardized measure--end of period............ $109,263  $147,272  $256,535
                                                  ========  ========  ========
1999:
  Standardized measure--beginning of period...... $ 30,964  $ 30,578  $ 61,542
  Sales of oil and gas produced, net of
   production costs..............................  (10,950)   (7,479)  (18,429)
  Purchases of minerals-in-place.................      187     1,491     1,678
  Extensions and discoveries.....................    3,198     1,100     4,298
  Sales of minerals-in-place.....................       --        --        --
  Net changes in prices and productions costs....   27,195    11,517    38,712
  Development costs incurred.....................      456       805     1,261
  Revisions to previous quantity estimates.......   14,144     1,672    15,816
  Accretion of discount..........................    3,096     4,706     7,802
  Changes in timing of production and other......   (7,608)   (2,795)  (10,403)
  Net changes in income taxes....................   (4,276)   (4,241)   (8,517)
                                                  --------  --------  --------
  Standardized measure--end of period............ $ 56,406  $ 37,354  $ 93,760
                                                  ========  ========  ========
</TABLE>

                                       59
<PAGE>

                            PETROCORP INCORPORATED

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

                       December 31, 2001, 2000 and 1999


   The standardized measure amounts are based on current prices at each year
end and reflect overall weighted average prices of:

<TABLE>
<CAPTION>
                                                             U.S.  Canada Total
                                                            ------ ------ ------
<S>                                                         <C>    <C>    <C>
2001:
  Oil (per BBL)............................................ $19.84 $19.73 $19.79
  Gas (per Mcf)............................................   2.70   2.32   2.48

2000:
  Oil (per BBL)............................................ $26.25 $29.73 $27.16
  Gas (per Mcf)............................................   9.98   8.85   9.19

1999:
  Oil (per BBL)............................................ $24.40 $22.84 $23.95
  Gas (per Mcf)............................................   2.35   1.80   1.95
</TABLE>

16. Supplementary Information

   At December 31, 2001, accrued liabilities included $1.3 million of accrued
lease operating expense, $1.4 million of accrued capital costs and $1.2
million of other miscellaneous expense. At December 31, 2000, accrued
liabilities included $.8 million of accrued lease operating expense, $1.0
million of accrued capital costs and $.7 million of other miscellaneous
expenses.

17. Summarized Quarterly Financial Data (unaudited)
    (amounts in thousands, except per share amounts)

<TABLE>
<CAPTION>
                                        First  Second   Third  Fourth
                                       quarter quarter quarter quarter   Year
                                       ------- ------- ------- -------  -------
<S>                                    <C>     <C>     <C>     <C>      <C>
Year ended December 31, 2001:
  Revenues............................ $13,769 $12,756 $13,807 $10,942  $51,274
  Gross profit(/1/)...................   9,925   6,249   5,468 (17,194)   4,448
  Income from operations..............   9,446   5,738   4,729 (17,724)   2,189
  Net income (loss)(/2/)..............   6,206   2,599   3,049  (9,808)   2,046
  Net income (loss) per share--
   basic(/2/)......................... $  0.71 $  0.27 $  0.24 $ (0.77) $  0.19
Year ended December 31, 2000:
  Revenues............................ $ 7,742 $ 9,203 $11,787 $15,841  $44,573
  Gross profit(/1/)...................   3,778   4,917   6,850  11,210   26,755
  Income from operations..............   3,394   4,840   6,422  11,015   25,671
  Net income (loss)(/3/)..............   1,510   2,330   3,264   5,714   12,818
  Net income (loss) per share--
   basic(/3/)......................... $  0.17 $  0.27 $  0.38 $  0.66  $  1.47
</TABLE>
--------
(/1/Revenues)less operating expenses other than general and administrative and
    restructuring costs.

(/2/Included)in the fourth quarter was a $1,092 ($0.10 per share) increase in
    the deferred income tax benefit due to a change in the estimated amount of
    depletion carryforward.

(/3/Net)income for the second quarter and year are net of a $242 extraordinary
    loss ($0.03 per share).


                                      60