<PAGE>

                                  UNITED STATES

                       SECURITIES AND EXCHANGE COMMISSION

                             Washington, D. C. 20549

                                   FORM 10-QSB

 [X]   QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
       ACT OF 1934

                  For the quarterly period ended March 31, 2002

                                       OR

[_]    TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
       ACT OF 1934

               For the transition period from ________ to ________

                          Commission File Number 1-7796

                              TIPPERARY CORPORATION
        (Exact name of small business issuer as specified in its charter)



Texas                                                75-1236955
(State or other jurisdiction of                      (I.R.S. Employer
incorporation or organization)                       Identification No.)

633 Seventeenth Street, Suite 1550
Denver, Colorado                                     80202
(Address of principal executive offices)             (Zip Code)


                                 (303) 293-9379
                           (Issuer's telephone number)

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


State the number of shares outstanding of each of the issuer's classes of common
stock, as of the latest practicable date.

             Class                             Outstanding  at May 14, 2002
----------------------------                   ----------------------------
Common Stock, $.02 par value                        38,971,489 shares
<PAGE>

                     TIPPERARY CORPORATION AND SUBSIDIARIES

                              Index to Form 10-QSB

                                                                        Page No.
                                                                        --------

PART I.  FINANCIAL INFORMATION (UNAUDITED)

         Item 1.  Financial Statements

                  Consolidated Balance Sheet
                  March 31, 2002 and December 31, 2001                       1

                  Consolidated Statement of Operations
                  Three months ended March 31, 2002 and 2001                 2

                  Consolidated Statement of Cash Flows
                  Three months ended March 31, 2002 and 2001                 3

                  Notes to Consolidated Financial Statements               4-8

         Item 2.  Management's Discussion and Analysis of
                  Financial Condition and Results of Operations           9-14


PART II. OTHER INFORMATION

         Item 1.  Legal Proceedings                                         15

         Item 2.  Changes in Securities                                     15

         Item 3.  Defaults Upon Senior Securities                           15

         Item 4.  Submission of Matters to a Vote of Security Holders       15

         Item 5.  Other Information                                         15

         Item 6.  Exhibits and Reports on Form 8-K                          15

SIGNATURES                                                                  16

<PAGE>

                         PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

                     TIPPERARY CORPORATION AND SUBSIDIARIES
                           Consolidated Balance Sheet
                                 (in thousands)
<TABLE>
<CAPTION>

                                                                              March 31              December 31
                                                                                2002                    2001
                                                                           ---------------        ---------------
                                                                              (unaudited)
<S>                                                                           <C>                    <C>
ASSETS
Current assets:
     Cash and cash equivalents                                                $   4,350              $   9,415
     Restricted cash                                                              1,964                  1,312
     Receivables                                                                  1,645                  2,518
     Prepaid drilling costs                                                         358                  2,821
     Other current assets                                                           226                    293
                                                                              ---------              ---------
         Total current assets                                                     8,543                 16,359
                                                                              ---------              ---------
Property, plant and equipment, at cost:
     Oil and gas properties, full cost method                                    77,652                 74,005
     Other property and equipment                                                 3,953                  3,903
                                                                              ---------              ---------
                                                                                 81,605                 77,908

Less accumulated depreciation, depletion and amortization                       (23,911)               (23,486)
                                                                              ---------              ---------
     Property, plant and equipment, net                                          57,694                 54,422
                                                                              ---------              ---------
Deferred loan costs                                                               6,339                  6,726
Other noncurrent assets                                                              20                     20
                                                                              ---------              ---------
                                                                              $  72,596              $  77,527
                                                                              =========              =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
     Current portion of long-term debt                                        $   2,473              $   2,231
     Accounts payable                                                               959                  4,022
     Accrued liabilities                                                          1,011                  1,004
     Royalties payable                                                              170                    234
                                                                              ---------              ---------
         Total current liabilities                                                4,613                  7,491
                                                                              ---------              ---------
Long-term debt, net of current portion                                           11,861                 12,183

Commitments and contingencies (Note 5)

Minority interest                                                                   583                    734

Stockholders' equity
     Preferred stock:
         Cumulative, $1.00 par value.  Authorized 10,000,000
              shares; none issued                                                     -                      -
         Non-cumulative, $1.00 par value.  Authorized
              10,000,000 shares; none issued                                          -                      -
     Common stock; par value $.02; 50,000,000 shares
         authorized; 38,981,087 issued and 38,971,489
         outstanding at March 31, 2002 and December 31, 2001                        780                    780
     Capital in excess of par value                                             149,502                149,499
     Accumulated deficit                                                        (94,718)               (93,135)
     Treasury stock, at cost; 9,598 shares                                          (25)                   (25)
                                                                              ---------              ---------
         Total stockholders' equity                                              55,539                 57,119
                                                                              ---------              ---------
                                                                              $  72,596              $  77,527
                                                                              =========              =========
</TABLE>

          See accompanying notes to consolidated financial statements.

                                       1
<PAGE>

                     TIPPERARY CORPORATION AND SUBSIDIARIES
                      Consolidated Statement of Operations
                      (in thousands, except per share data)
                                   (unaudited)
<TABLE>
<CAPTION>


                                                             Three months ended
                                                                  March 31
                                                         --------------------------
                                                           2002             2001
                                                         ---------       ----------
<S>                                                      <C>             <C>
Revenues                                                 $   1,352       $     869
                                                         ---------       ---------
Costs and expenses:
   Operating                                                   592             462
   Depreciation, depletion and amortization                    423             210
   General and administrative                                1,547             977
                                                         ---------       ---------
        Total costs and expenses                             2,562           1,649
                                                         ---------       ---------
Operating loss                                              (1,210)           (780)

Other income (expense):
   Other income                                                 70               -
   Interest income                                              16              47
   Interest expense                                           (632)           (461)
   Foreign currency exchange gain (loss)                        23             (92)
                                                         ---------       ---------
        Total other expense                                   (523)           (506)
                                                         ----------      ---------
Loss before income taxes                                    (1,733)         (1,286)

Income tax expense (benefit)                                     -               -
                                                         ---------       ---------
Net loss before minority interest                           (1,733)         (1,286)

Minority interest in loss of subsidiary                        150              91
                                                         ---------       ---------
Net loss                                                 $  (1,583)      $  (1,195)
                                                         =========       =========
Net loss per share
   Basic and diluted                                     $    (.04)      $    (.05)
                                                         =========       =========
Weighted average shares outstanding
   Basic and diluted                                        38,971          24,473
                                                         =========       =========
</TABLE>

          See accompanying notes to consolidated financial statements.

                                        2
<PAGE>

                     TIPPERARY CORPORATION AND SUBSIDIARIES
                      Consolidated Statement of Cash Flows
                                 (in thousands)
                                   (unaudited)

<TABLE>
<CAPTION>
                                                                                  Three months ended
                                                                                       March 31
                                                                             ---------------------------
                                                                                2002              2001
                                                                             ---------          --------
<S>                                                                           <C>               <C>
Cash flows from operating activities:
Net loss                                                                      $ (1,583)         $ (1,195)
Adjustments to reconcile net loss to net cash
     used in operating activities:
         Depreciation, depletion and amortization                                  423               210
         Amortization of deferred loan costs                                       396               129
         Compensatory warrants granted                                               3                 -
         Minority interest in loss of subsidiary                                  (150)              (91)
         Change in assets and liabilities:
         Decrease in receivables                                                   468               352
         Decrease in other current assets                                        2,530               242
         Decrease in accounts payable and
           accrued liabilities                                                  (3,300)           (1,387)
         (Decrease) increase in royalties payable                                  (64)               35
                                                                              --------          --------
Net cash used in operating activities                                           (1,277)           (1,705)
                                                                              --------          --------

Cash flows from investing activities:
     Proceeds from asset sales                                                     779                 -
     Capital expenditures                                                       (3,835)           (6,192)
                                                                              --------          --------
Net cash used in investing activities                                           (3,056)           (6,192)
                                                                              --------          --------
Cash flows from financing activities:
     Proceeds from borrowings                                                        -            14,500
     Principal repayments                                                          (80)           (4,407)
     Increase in restricted cash                                                  (652)           (1,383)
     Payments for deferred loan costs                                                -              (712)
                                                                              --------          --------
Net cash provided by (used in) financing activities                               (732)            7,998
                                                                              --------          --------
Net increase (decrease) in cash and cash equivalents                            (5,065)              101

Cash and cash equivalents at beginning of period                                 9,415             1,579
                                                                              --------          --------
Cash and cash equivalents at end of period                                    $  4,350          $  1,680
                                                                              ========          ========
Supplemental disclosure of cash flow information:
     Cash paid during the period for:
         Interest                                                             $    501          $    307
         Income taxes                                                         $      -          $      -
     Non-cash investing and financing activities:
         Issuance of stock to acquire assets                                  $      -          $  1,688
         Issuance of subsidiary stock to stockholder in exchange for
           contractual payment rights                                         $      -          $  1,074
         Net decrease in payables for capital expenditures                    $    646          $      -

</TABLE>








          See accompanying notes to consolidated financial statements.

                                       3
<PAGE>

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                                   (Unaudited)

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

In the opinion of management, the accompanying unaudited consolidated financial
statements reflect all adjustments, consisting only of normal recurring
adjustments, which are necessary for a fair presentation of the financial
position of Tipperary Corporation and its subsidiaries (the "Company") at March
31, 2002, and the results of its operations and its cash flows for the
three-month periods ended March 31, 2002 and 2001. The consolidated financial
statements include the accounts of the Company and its wholly-owned
subsidiaries, Tipperary Oil and Gas Corporation and Burro Pipeline Corporation,
and its 90%-owned subsidiary, Tipperary Oil and Gas (Australia) Pty Ltd
("TOGA"), and its share of assets, liabilities, revenues and expenses of
unincorporated joint ventures. All intercompany balances have been eliminated.
The accounting policies followed by the Company are included in Note 1 to the
Consolidated Financial Statements in its Annual Report on Form 10-KSB for the
year ended December 31, 2001. These financial statements should be read in
conjunction with the Form 10-KSB.

Impact of New Accounting Pronouncements

In April 2002, the Financial Accounting Standards Board ("FASB") issued SFAS 145
"Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No.
13, and Technical Corrections" which is generally effective for transactions
occurring after May 15, 2002. Through the rescission of FASB Statements 4 and
64, SFAS 145 eliminates the requirement that gains and losses from
extinguishment of debt be aggregated and, if material, be classified as an
extraordinary item net of any income tax effect. SFAS 145 makes several other
technical corrections to existing pronouncements that may change accounting
practice. The Company has not yet determined whether SFAS 145 will have a
material impact on its financial position or results of operations.

In August 2001, FASB issued SFAS 144 "Accounting for the Impairment or Disposal
of Long-Lived Assets," which replaces SFAS 121, "Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to be Disposed of." SFAS 144
requires that long-lived assets to be disposed of by sale be measured at the
lower of the carrying amount or fair value less selling costs, whether reported
in continuing operations or in discontinued operations. SFAS 144 changes the
reporting of discontinued operations to include all components of an entity with
operations that can be segregated from the rest of the entity and that will be
eliminated from the ongoing operations of the entity as a result of a disposal
transaction. The Company adopted SFAS 144 effective January 1, 2002; however,
because the Company uses the full cost method of accounting, the provisions of
Rule 410 in Regulation S-X must be followed in accounting for the Company's oil
and gas operations instead of those in SFAS 144.

In July 2001, the FASB issued SFAS 141 "Business Combinations" and SFAS 142,
"Goodwill and Other Intangible Assets." SFAS 141 requires that all business
combinations entered into subsequent to June 30, 2001 be accounted for under the
purchase method of accounting and that certain acquired intangible assets in a
business combination be recognized and reported as assets separately from
goodwill. SFAS 142 requires that amortization of goodwill be replaced with an
annual impairment test of the goodwill's carrying value. The Company adopted
SFAS 141 in July 2001 and adopted SFAS 142 effective January 1, 2002. The
adoption of SFAS 141 and SFAS 142 did not have a material effect on the
Company's financial position or results of operations.

In June 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement
Obligations," which provides accounting requirements for retirement obligations
associated with tangible long-lived assets, including the timing of liability
recognition, initial measurement of the liability, allocation of asset
retirement costs to expense, subsequent measurement of the liability, and
financial statement disclosures. SFAS 143 requires that asset retirement costs
be capitalized along with the cost of the related long-lived asset. The asset
retirement costs should then be allocated to expense using a systematic and
rational method. The transition adjustment resulting from the adoption of SFAS
143 would be reported as a cumulative effect of a change in accounting
principle. The Company will adopt SFAS 143 no later than January 1,

                                       4
<PAGE>

2003. The Company has not yet determined whether SFAS 143 will have a material
impact on its financial position or results of operations.

Gas Imbalances

In natural gas production operations, joint owners may sell more or less than
the production volumes to which they are entitled based on their revenue
ownership interest. The joint operating agreement on the Comet Ridge project
includes gas balancing provisions to govern production allocations in this
situation. The Company records a natural gas imbalance in other liabilities if
its excess takes of natural gas exceed its remaining proved reserves for the
property. As of March 31, 2002, the Company had taken and sold more than its
share of natural gas volumes produced from the Comet Ridge project, and was
overproduced by approximately 886,000 Mcf. Based on the average price of $1.16
per Mcf received during 2002 from these sales, this represents $1,028,000 in gas
revenues. No liability has been recorded for the excess volumes taken as they do
not exceed the Company's share of remaining proved reserves. Under the terms of
the gas balancing agreement, the Company may be required to reduce the monthly
volumes it delivers by up to 50% in order to enable underproduced parties to
take more than their share of the gas and cure the imbalance. If the imbalance
were to be corrected over a relatively short term, it would adversely affect
revenues and cash flows during that period.

Liquidity and Operations

The Company anticipates that cash on hand, which includes $5 million of
additional borrowings from TCW Asset Management Company ("TCW") received in
April 2002 (See Note 3), will fund operations and capital expenditures through
2002. In order to fund any capital expenditures in 2002 in excess of these cash
resources and to fund capital expenditures beyond 2002, the Company will require
alternative sources of capital. The Company intends to seek debt financing for
further development of the Comet Ridge project and will continue to seek
industry partners in domestic exploration projects. With the sale of interests
in its exploration acreage, the Company expects to generate cash to reduce its
investment in individual projects. However, in the event that sufficient funding
cannot be obtained, the Company will be required to curtail planned expenditures
and may have to sell additional acreage and/or relinquish acreage.

NOTE 2 - RELATED PARTY TRANSACTIONS

Slough Estates USA, Inc. ("Slough"), the Company's largest (63.3%) shareholder,
has advanced the Company $2,500,000 for the purchase of a drilling rig which it
has leased to an unaffiliated drilling contractor in Australia. This loan bears
interest at a fixed rate of 10% per annum and matures on July 31, 2003. Payments
are due monthly equal to all rents the Company receives from the drilling
contractor and for accrued interest on the balance of the loan. As of March 31,
2002, the balance due on this loan was $2,345,000. The Company has recorded a
current liability for $840,000 of the loan balance based on projected rental
payments expected from the drilling contractor through March 31, 2003.

NOTE 3 - LONG-TERM DEBT - UNRELATED PARTY

The Company is a party to an amended and restated Credit Agreement with TCW.
This Credit Agreement provides a borrowing facility of up to $17 million. The
obligation to repay debt is evidenced by senior secured promissory notes bearing
interest at the rate of 10% per annum and payable quarterly. The Company must
also make monthly payments to TCW equal to a 6% overriding royalty from the gas
sales revenues received by TOGA from the Comet Ridge project. Upon payment of
the loan in full, TCW has the option to sell this overriding royalty interest to
the Company at the net present value of the royalty interest's share of future
net revenues from the then proved reserves, discounted at a rate of 15% per
annum. The Company also has the right to purchase the royalty interest from TCW,
when the loan has been repaid in full and TCW has received a 15% internal rate
of return on its investment, for the net present value of the royalty interest's
share of future net revenues from the then proved reserves, discounted at a rate
of 15% per annum. Principal payments are due quarterly in an amount equal to the
greater of a percentage of TOGA's operating cash flow as defined or a scheduled
minimum principal payment. The scheduled minimum principal payments begin in
March 2003 and will be equal to 5% of the unpaid principal balance, increasing
to 9% in March 2004 and 10% in March 2005. The outstanding principal balance is
due in full on March 30, 2006. If the Company fails to make principal payments
as required by the Credit Agreement, TCW may require all obligations to be
immediately due and payable. The Credit Agreement requires that TOGA maintain
working capital of at least $1,000,000.

                                       5
<PAGE>

In February 2001, the Company received an initial loan advance of $7.5 million.
Proceeds were used to repay the $4,406,000 project-financing loan relating to
the Comet Ridge project in Queensland, Australia due to Slough, and pay
$1,500,000 in initial costs of an additional 20-well drilling program on the
Comet Ridge project, with the balance provided as working capital for
lender-approved purposes. During 2001, the Company received $4.5 million of
additional loan advances under the Credit Agreement, bringing the total loan
balance to $12 million. In April 2002, the Company borrowed the remaining $5
million under the facility.

Upon the receipt of the initial funding, the Company recorded deferred financing
costs of approximately $6,800,000, which was the then present value (discounted
at 15%) of the overriding royalty conveyed to TCW. This cost reduced the book
value of oil and gas properties and is being amortized as interest expense over
the life of the loan. Deferred loan costs at March 31, 2002 also include
approximately $1,196,000 of other costs incurred to obtain the TCW financing,
which are likewise being amortized to interest expense over the life of the
loan.

NOTE 4 - EARNINGS (LOSS) PER SHARE

The following table sets forth the computation of basic and diluted earnings
(loss) per share ("EPS") (in thousands except per share data):

<TABLE>
<CAPTION>

                                                                                Three months ended
                                                                                     March 31
                                                                             ------------------------
                                                                               2002            2001
                                                                             --------       ---------
<S>                                                                          <C>             <C>
Numerator:
   Net loss                                                                  $ (1,583)       $ (1,195)

Denominator:
   Weighted average shares outstanding                                         38,971          24,473
   Effect of dilutive securities:
        Assumed conversion of dilutive options                                      -               -
                                                                             --------        --------
        Weighted average shares and dilutive potential
           common shares                                                       38,971          24,473
                                                                             ========        ========
Basic and diluted loss per share                                             $   (.04)       $   (.05)
                                                                             ========        ========
Potentially dilutive common stock from the exercise
        of options and warrants not included in EPS
        that would have been antidilutive                                          50             983
                                                                             ========        ========
Total common stock and warrants which could
        potentially dilute basic EPS in future periods                          3,520           3,513
                                                                             ========        ========
</TABLE>


NOTE 5 - COMMITMENTS AND CONTINGENCIES

The Company is plaintiff in a lawsuit filed on August 6, 1998, styled Tipperary
Corporation and Tipperary Oil & Gas (Australia) Pty Ltd v. Tri-Star Petroleum
Company, Cause No. CV42,265, in the District Court of Midland County, Texas
involving the Comet Ridge project. By amended petition filed May 1, 2000,
Tipperary Oil & Gas Corporation joined the action as a plaintiff, along with the
already-named plaintiffs and two unaffiliated non-operating working interest
owners who previously intervened in the action as plaintiffs. James H. Butler,
Sr., and James H. Butler, Jr., owners of defendant Tri-Star Petroleum Company,
were also named as defendants in the amended petition. The Company and the other
plaintiffs allege, among other matters, that Tri-Star and/or the individual
defendants have failed to operate the properties in a good and workmanlike
manner and have committed various other breaches of a joint operating contract,
have breached a previous mediation agreement between the parties, have committed
certain breaches of fiduciary and other duties owed to the plaintiffs, and have
committed fraud in connection with the project. Tri-Star has answered the
amended petition, and on December 22, 2000, Tri-Star filed its first amended
counterclaim alleging tortious interference with the contracts, with the
authority to prospect covering the project and with contractual relationships
with

                                       6
<PAGE>

vendors; commercial disparagement; foreclosure of operator's lien and
alternatively forfeiture of undeveloped acreage; unjust enrichment and
declaratory relief. As of February 8, 2001, the court enjoined Tri-Star from
asserting any forfeiture claims based upon events prior to that date. On March
11, 2002, the court entered a Writ of Temporary Injunction, and an Amended Writ
of Temporary Injunction on March 13, 2002, to enforce the votes of a
majority-in-interest of the parties under the joint operating agreement to
remove Tri-Star as operator and replace it with TOGA. The orders provided that
TOGA take over operations on March 22, 2002. On March 15, 2002, Tri-Star filed a
Notice of Accelerated Appeal of the March 11, 2002 Order Granting Injunctive
Relief Regarding Removal of Tri-Star Petroleum Company as Operator. The appeal
will be heard by the Texas Eighth Court of Appeals in El Paso. The lower court
denied Tri-Star's request for a stay of enforcement of the injunctive orders.
Tri-Star sought a stay from the Court of Appeals, which was likewise denied.
TOGA assumed operation of the Comet Ridge project on March 22, 2002, under the
terms of the orders. An evidentiary hearing relating to the May 2, 1996
Mediation Agreement between the parties and the obligation of the parties to
arbitrate audit disputes began on April 29, 2002, and a ruling by the trial
court is expected in the near term. The pending appeal has delayed the trial on
the merits, and a new trial date will not be set before the appellate case is
resolved. While the appeal will be heard on an expedited basis, it is not
possible to predict the length of the appellate process.

Through March 31, 2002, the Company has made payments totaling approximately
$1.2 million into the registry of the court for disputed portions of joint
interest billings from Tri-Star. At the appropriate time, the court will
determine the disposition of the funds paid into its registry. The funds may be
returned to the Company, in whole or in part, or awarded to Tri-Star in whole or
in part. If, and to the extent funds are returned, the Company will reduce its
full cost pool for recovered capital costs and will record a gain for recovered
operating costs. If, and to the extent funds are awarded to Tri-Star, the
Company will not record an additional loss.

In 1997, the Company filed a complaint along with ten other plaintiffs in BTA
Oil Producers, et al. v. MDU Resources Group, Inc. in Stark County Court in the
Southwest Judicial District of North Dakota for breach of gas sales contracts
and processing agreements, unjust enrichment, implied trust and related business
torts. The case concerned the sale by plaintiffs and certain predecessors of
natural gas processed at the McKenzie Gas Processing Plant in North Dakota to
Koch Hydrocarbons Company. It also concerned the contracts for resale of that
gas to MDU Resources Group, Inc. and Williston Basin Interstate Pipeline
Company. The trial court entered two summary judgment orders deciding the issues
in the case. The case was appealed by the Company to the North Dakota Supreme
Court and the Company was not successful in the appeal. The Company may join
with other plaintiffs in seeking a rehearing to the North Dakota Supreme Court,
but does not believe that a rehearing is likely. Costs incurred with respect to
this litigation have been limited to expenses rather than fees and have not been
material.

NOTE 6 - OPERATIONS BY GEOGRAPHIC AREA

The Company has one operating and reporting segment - oil and gas exploration,
development and production - in the United States and Australia. Information
about the Company's operations by geographic area is shown below (in thousands):

<TABLE>
<CAPTION>

                                                              United
                                                              States             Australia            Total
                                                            -----------         ----------         -----------
<S>                                                         <C>                 <C>                <C>
Three months ended March 31, 2002
     Revenues                                               $       395         $      957         $     1,352
     Property, plant and equipment, net                     $     9,846         $   47,848         $    57,694

Three months ended March 31, 2001
     Revenues                                               $       321         $      548         $       869
     Property, plant and equipment, net                     $     8,290         $   37,254         $    45,544
</TABLE>

                                       7
<PAGE>

NOTE 7 - ASSET SALES AND ACQUISITIONS

During the quarter ended March 31, 2002, the Company sold a 60% interest in
conventional oil and gas exploration acreage located in Moffat County, Colorado,
to an unaffliated purchaser for approximately $595,000. The proceeds reduced the
Company's domestic full cost pool and no gain or loss was recorded. The purchase
and sale agreement also provided that the purchaser pay one-half of the
Company's 40% share of drilling costs through casing point for the first well.

Subsequent to March 31, 2002, the Company has entered into an agreement with an
unaffiliated third party, Delta Petroleum Corporation ("Delta") whereby the
Company will sell to Delta all of the Company's undivided interests in the West
Buna field in Jasper and Hardin counties, Texas, and will purchase all of
Delta's undivided interests in certain Authorities to Prospect (ATPs) in
Queensland, Australia. Under the terms of the agreement, the Company is to
receive $4.1 million in cash proceeds from the sale of the West Buna property
and will acquire Delta's interests in Australia for a purchase price of $5.25
million. The assets in Queensland, Australia include Delta's 5% interest in the
Comet Ridge project on ATP 526 and interests of 2.5% or less in each of six
other ATPs that have no proved reserves. The purchase price will include $4.8
million in cash and 250,000 unregistered shares of the Company's common stock.
The Company also will assume up to $600,000 of obligations owed by Delta related
to the Comet Ridge project. This acquisition will increase the Company's total
capital-bearing interest in the Comet Ridge project from 65% to 70%. The
transactions are expected to close simultaneously in late May, 2002. The Company
expects to record a loss upon completion of the West Buna asset sale under the
full cost method of accounting.

                                        8
<PAGE>

Item 2.  Management's Discussion and Analysis

Information within this report contains forward-looking statements within the
meaning of the Private Securities Litigation Reform Act of 1995 that are based
on management's beliefs, assumptions, current expectations, estimates and
projections about the oil and gas industry, the world economy and about the
Company itself. Words such as "may," "will," "expect," "anticipate," "estimate"
or "continue," or comparable words are intended to identify such forward-looking
statements. In addition, all statements other than statements of historical
facts that address activities that the Company expects or anticipates will or
may occur in the future are forward-looking statements. These statements are not
guarantees of future performance and involve certain risks, uncertainties and
assumptions that are difficult to predict with regard to timing, extent,
likelihood and degree of occurrence. Therefore, actual results and outcomes may
materially differ from what may be expressed or forecasted in such
forward-looking statements. Furthermore, the Company undertakes no obligation to
update, amend or clarify forward-looking statements, whether as a result of new
information, future events or otherwise. Readers are encouraged to read the SEC
filings of the Company, particularly its Form 10-KSB for the year ended December
31, 2001, for meaningful cautionary language disclosing why actual results may
vary materially from those anticipated by management.

Overview

Australia

The Company's activities in Australia are conducted through its 90%-owned
Australian subsidiary, Tipperary Oil & Gas (Australia) Pty Ltd ("TOGA"). TOGA
owns a 65% undivided interest in the Company's primary producing property
located in Queensland, Australia (the "Comet Ridge project"). This project
comprises approximately 964,000 acres in the Bowen Basin, including Authority to
Prospect ("ATP") 526 covering approximately 686,000 acres and five petroleum
leases covering approximately 278,000 acres.

An ATP allows the holder to undertake a range of exploration activities,
including geophysical surveys, field mapping and exploratory drilling. Each ATP
requires the expenditure of an amount of exploration costs approved by
Queensland's Department of Natural Resources and Mines and is subject to renewal
every four years. Once a petroleum resource is identified, the holder of an ATP
may apply for a petroleum lease, which provides the lessee with the ability to
conduct additional exploration, development and production activities.

The most recent renewal of ATP 526 expires on October 31, 2004 and includes
expenditure requirements over the four-year term of approximately US$8 million,
or approximately US$5.1 million net to the Company's interest. The Company
expects to satisfy the portion of the expenditure requirement through October
31, 2002, with its recently-proposed seven-well exploratory drilling program,
which is expected to commence in June 2002. The estimated cost of this drilling
program is $4,679,000, of which the Company's share is approximately $3 million.
The Company has offered non-recourse financing to the other working interest
owners for their share of the estimated costs. The owners are entitled to make
an election whether to participate in drilling the exploration wells and whether
to accept the financing offered by Tipperary. The Company intends to use $5
million received in April 2002 from TCW Asset Management Company ("TCW") to fund
this drilling program. The TCW debt facility is discussed below and in Note 3 to
the Consolidated Financial Statements.

A total of 54 wells have been drilled on the Comet Ridge project. There are 40
producing wells in the Fairview area in the southern portion of ATP 526 and 14
wells in various stages of completion. The Company is selling gas from 19 of the
producing wells that are connected to a gathering system which supplies a
compressor station feeding into a regulated gas pipeline. The remaining 21
producing wells are either being dewatered or are shut in pending connection.
Production from the Comet Ridge wells currently totals approximately 20 million
cubic feet ("MMcf") of gas per day, of which approximately 15 MMcf is being
sold. The gas not being sold is either being flared at the wellhead (3 MMcf per
day) pending connection to the gathering system or is used in gas compression
and dehydration equipment (2 MMcf per day).

A 20-well development-drilling program on the Comet Ridge project is nearing
completion, with the remaining wells scheduled to be drilled and completed by
the end of June 2002. The Company expects to have all of the wells

                                       9
<PAGE>

connected and selling gas by the end of the third quarter of 2002. The Company
has funded its share of the drilling costs with financing received under the TCW
borrowing facility.

On March 22, 2002, the Company assumed operation of the Comet Ridge project
pursuant to orders issued by the 238th Judicial District Court in Midland
County, Texas. The Court's ruling granted the application of the Company and
others for a temporary injunction requiring the then operator of the project to
turn over operations to TOGA. The right of the Company and other non-operators
to remove the operator and install a successor operator has been the subject of
litigation, which is discussed in Note 5 to the Consolidated Financial
Statements.

The court also found that the evidence presented by the Company and other
applicants at the injunctive hearing showed a probable right of recovery upon a
trial on the merits. The trial, which had been scheduled for April 29, 2002, was
postponed due to an appeal of the injunctive orders filed by the defendant.
Although the appeal will be heard on an expedited basis, the Company cannot
predict when it will be concluded.

In addition to the interest in the Comet Ridge property, TOGA holds interests in
other exploration permits which cover a total of approximately 1.5 million acres
The Company does not expect to incur a substantial capital investment in these
ATPs during 2002.

United States

The Company has a 50% working interest in and serves as operator of the Lay
Creek project in Moffat County, Colorado. The project includes various leasehold
interests covering over 82,000 acres. Koch Exploration Company ("Koch"), an
unaffiliated third party, holds the remaining 50% working interest under the
terms of an agreement to jointly conduct exploratory drilling over this area.
Koch paid the Company approximately $2 million for this interest at closing in
May 2001 and agreed to pay the Company approximately $2 million for the
Company's share of costs to drill and complete wells on the project acreage. The
Company drilled and completed two exploratory coalbed methane wells on this
acreage during 2001 and completed a four-well pilot drilling program in early
May 2002. The Company will be evaluating the gas and water production from these
wells during 2002 in order to determine if the gas production will be
economically viable.

The Company established a receivable for the $2 million to be received from Koch
for reimbursement of the Lay Creek drilling costs discussed above. The
receivable has been reduced by approximately $1,246,000 for costs incurred to
drill and complete the two wells and to begin work on the four well pilot
drilling program, leaving a balance as of March 31, 2002 of $754,000 due the
Company on or before October 4, 2002. The Company expects to realize the
remaining balance of this receivable during the second quarter of 2002 through
Koch's payment of the Company's share of drilling and completion costs.

The Company recently sold a 60% interest in the Nine Mile Prospect, a
conventional oil and gas exploration project, which is also located in Moffat
County, Colorado, to an unaffiliated purchaser for approximately $595,000. The
purchaser is currently conducting exploratory operations on this prospect.

In addition to the aforementioned projects, the Company has leased approximately
266,000 acres in other areas of Colorado as of March 31, 2002. As it has with
its other acreage, the Company will seek industry partners to join in the
exploration of these prospective areas.

The Company has been involved in the Hanna Basin coalbed methane project in
Wyoming operated by Williams Production RMT Company. In March 2002, the Company
decided that the dewatering process and expected gas production did not indicate
economics suitable to the Company and it is exploring its options to divest its
interest in the project. Under the full cost method of accounting, unevaluated
acreage and unevaluated exploratory costs are excluded from the amortization
computation until the related property is evaluated as either having proved
reserves or as impaired. Based on the Company's decision to sell its interest in
this project, the associated costs will be included in the amortization base
beginning with the second quarter of 2002.

                                       10
<PAGE>

The Company has announced its intention to sell its West Buna property on or
before May 24, 2002. This east Texas property is the Company's only remaining
domestic producing asset following a divestiture of most of the Company's U.S.
oil and gas holdings during fiscal 2000. The Company reported total natural gas
equivalent reserves of approximately 4.3 billion cubic feet and a present value,
discounted at 10%, of approximately $5.8 million associated with this property
as of December 31, 2001. See Note 7 to the Consolidated Financial Statements.

Financial Condition, Liquidity and Capital Resources

The Company anticipates that cash on hand, which includes $5 million of
additional borrowings received from TCW in April 2002, will fund operations and
capital expenditures through 2002. In order to fund any capital expenditures in
2002 in excess of these cash resources and to fund capital expenditures beyond
2002, the Company will require alternative sources of capital. The Company
intends to seek debt financing for further development of the Comet Ridge
project and will continue to seek industry partners in domestic exploration
projects. With the sale of interests in its exploration acreage, the Company
expects to generate cash to reduce its investment in individual projects.
However, in the event that sufficient funding cannot be obtained, the Company
will be required to curtail planned expenditures and may have to sell additional
acreage and/or relinquish acreage.

The Company had unrestricted cash and cash equivalents of $4,350,000 as of March
31, 2002, compared to $9,415,000 as of December 31, 2001. At March 31, 2002, the
Company had working capital of $3,930,000 compared to working capital of
$8,868,000 as of December 31, 2001. Working capital includes restricted cash of
$1,964,000 as of March 31, 2002 and $1,312,000 as of December 31, 2001. The
restricted cash as of March 31, 2002 includes cash in collateral accounts
maintained in connection with the TCW financing, the use of which is restricted
to disbursements made either to TCW or as otherwise approved by TCW. The
restricted cash at December 31, 2001 also relates to cash in collateral accounts
maintained in connection with the TCW financing. During the three months ended
March 31, 2002, cash flows were provided by existing cash balances. Available
cash was used to fund capital expenditures and operating activities.

Net cash used by operating activities was $1,277,000 during the three months
ended March 31, 2002 compared to $1,705,000 of cash used during the same period
last year. The need to use cash for operations in both periods resulted from the
sale of most of the Company's U.S. oil and gas properties as of June 30, 2000.
However, the loss in revenues from domestic properties has been partially offset
by steadily increasing sales of natural gas in Australia. See Results of
Operations below.

During the three months ended March 31, 2002, the Company had no significant
financing activity. Capital expenditures of $3,835,000 included $2,807,000 for
drilling costs in the Comet Ridge project, $22,000 for capital costs on other
ATP's in Australia, $938,000 for domestic leasehold cost acquisitions and
$68,000 for capital costs in the West Buna field. The Company's share of costs
to begin drilling operations on a four well pilot program in the Lay Creek
project was $529,000, which will be reimbursed by Koch. Proceeds of $779,000
during the three months ended March 31, 2002 included $594,000 received from the
sale of a 50% interest in the Nine Mile prospect in Colorado and $185,000 in
reimbursed Lay Creek drilling costs under the terms of the purchase and sale
agreement with Koch. The Company received approximately $2 million from Koch at
closing and has received or billed $1,246,000 for costs related to the wells
recently drilled at Lay Creek. Approximately $754,000, shown as a current
receivable, is required to be paid to the Company by Koch through the
reimbursement of drilling costs or in cash on or before October 4, 2002.

For the prior year's quarter ended March 31, 2001, the Company had net receipts
of $7,998,000 from financing, which included borrowings of $7,500,000 from TCW
and $4,500,000 from Slough. Capital expenditures of $6,192,000 included
$2,076,000 for the purchase of a drilling rig to be leased to a drilling
contractor in Queensland, Australia, $1,718,000 for acreage acquisitions in
Colorado, $1,293,000 for drilling, completion and other costs on the Comet Ridge
project and $932,000 for drilling and completion costs in the Hanna Basin of
Wyoming.

In February 2001, the Company received an initial loan advance of $7.5 million
under the $17 million borrowing facility with TCW. Proceeds from this initial
advance were used to repay Slough for the Comet Ridge project-financing loan of
$4,406,000, pay $1,500,000 in initial costs of the 20-well drilling program on
the Comet Ridge project and pay approximately $240,000 of expenses related to
the financing. The balance of $1,354,000 was deposited into a collateral

                                       11
<PAGE>

account as restricted working capital to be used for lender-approved purposes.
Upon the receipt of this initial funding, the Company recorded deferred
financing costs of $6.8 million for the present value (discounted at 15%) of the
overriding royalty conveyed to TCW. This cost reduced the book value of oil and
gas properties and is amortized as interest expense over the life of the loan.
Deferred loan costs also include approximately $1,196,000 of other costs
incurred to obtain the TCW financing, which are likewise being amortized to
interest expense over the life of the loan.

During 2001, the Company received $4.5 million of additional loan advances under
the TCW Credit Agreement, bringing the total loan balance to $12 million. In
April 2002, the Company borrowed the remaining $5 million under the facility.

The obligation to repay the TCW advances and accrued interest is evidenced by
senior secured promissory notes bearing interest at the rate of 10% per annum
and payable quarterly. The Company must also make monthly payments to TCW equal
to a 6% overriding royalty from the gas sales revenues received by TOGA from the
Comet Ridge project. Upon payment of the loan in full, TCW has the option to
sell this overriding royalty interest to the Company at the net present value of
the royalty interest's share of future net revenues from the then proved
reserves, discounted at a rate of 15% per annum. The Company has the right to
purchase the interest from TCW, when both the loan has been repaid in full and
TCW has achieved a 15% internal rate of return on its investment, at the net
present value of the royalty interest's share of future net revenues from the
then proved reserves, discounted at a rate of 15% per annum. Principal payments
on the TCW financing are due quarterly in an amount equal to the greater of a
percentage of TOGA's operating cash flow as defined, or a scheduled minimum
principal payment. The scheduled minimum principal payments begin March 2003 and
will be equal to 5% of the unpaid principal balance, increasing to 9% in March
2004 and 10% in March 2005. The outstanding principal balance is due in full on
March 30, 2006. If the Company fails to make principal payments as required by
the Credit Agreement, TCW may require all obligations to be immediately due and
payable. The Credit Agreement requires that TOGA maintain working capital of at
least $1,000,000.

In January 2001, TOGA acquired and thereafter leased a drilling rig to an
unaffiliated drilling contractor in Queensland, Australia ("Lessee"). The terms
of the lease agreement provide that the Lessee will use the rig to drill on the
Comet Ridge project and/or TOGA's ATPs. To the extent the rig is not being used
for TOGA's drilling activities, it may, with TOGA's consent, be used by the
Lessee to drill wells for others. The lease payments are structured to be due
and payable with the drilling of each well on which the rig is used. No interest
or finance charge accrues on the lease, but the Company will benefit from
reduced costs to drill wells on TOGA's ATPs. The Lessee also received a two-year
option to buy the rig and related equipment at TOGA's net cost.

In January 2001, Slough advanced the Company $2,500,000 to finance the purchase
of the drilling rig. This loan bears interest at a rate of 10% per annum.
Payments are due monthly for all rents TOGA receives from the drilling
contractor during the month and for accrued interest on the balance of the loan.
As of March 31, 2002, the balance due on this loan was $2,345,000. The Company
has recorded a current liability for $840,000 of the loan, based on projected
rental payments expected from the drilling contractor by March 31, 2003.

Results of Operations - Comparison of the Three Months Ended March 31, 2002 and
2001

The Company incurred a net loss of $1,583,000 for the three months ended March
31, 2002, compared to a net loss of $1,195,000 for the three months ended March
31, 2001. The net loss in both periods is primarily attributable to reduced
revenues due to the sale of most of the Company's producing properties in the
U.S. during 2000. The table below provides a comparison of operations for the
three months ended March 31, 2002 with those of the prior year's quarter.

                                       12
<PAGE>

<TABLE>
<CAPTION>

                                                                       Three Months Ended
                                                                             March 31                  Increase       % Increase
                                                                      2002            2001            (Decrease)     (% Decrease)
                                                                  -----------      -----------       -----------     --------------
<S>                                                                <C>              <C>               <C>               <C>
Worldwide operations:

Operating revenue                                                  $1,352,000       $  869,000        $  483,000          56%
Gas volumes (Mcf)                                                     819,000          513,000           306,000          60%
Oil volumes (Bbls)                                                     10,000            4,800             5,200         108%
Average gas price per Mcf                                          $     1.30       $     1.43        $    (0.13)         (9%)
Average oil price per Bbl                                          $    20.11       $    28.35        $    (8.24)        (29%)
Operating expenses                                                 $  592,000       $  462,000        $  130,000          28%
Average lifting cost per Mcf equivalent ("Mcfe")                   $     0.69       $     0.86        $    (0.17)        (20%)
General and administrative                                         $1,547,000       $  977,000        $  570,000          58%
Depreciation, depletion and amortization ("DD&A")                  $  423,000       $  210,000        $  213,000         101%
DD&A rate per Mcfe volumes sold                                    $     0.48       $     0.36        $     0.12          33%
Interest expense                                                   $  632,000       $  461,000        $  171,000          37%
Foreign currency exchange gain (loss)                              $   23,000       $  (92,000)       $  115,000         N/A

Domestic operations:

 Operating revenue                                                 $  395,000       $  321,000        $   74,000          23%
 Gas volumes (Mcf)                                                     60,000           23,000            37,000         161%
 Oil volumes (Bbls)                                                    10,000            4,800             5,200         108%
 Average gas price per Mcf                                         $     3.18       $     8.01        $    (4.83)        (60%)
 Average oil price per Bbl                                         $    20.11       $    28.35        $    (8.24)        (29%)
 Operating expenses                                                $  114,000       $  148,000        $  (34,000)        (23%)
 Average lifting cost per Mcfe                                     $     1.08       $     2.86        $    (1.78)        (62%)
 DD&A                                                              $  129,000       $   55,000        $   74,000         135%
 DD&A rate per Mcfe volumes sold                                   $     1.08       $     0.83        $     0.25          30%

Australia operations:

 Operating revenue                                                 $  957,000       $  548,000        $  409,000          75%
 Gas volumes (Mcf)                                                    759,000          490,000           269,000          55%
 Average gas price per Mcf                                         $     1.16       $     1.12        $     0.04           4%
 Operating expenses                                                $  478,000       $  314,000        $  164,000          52%
 Average lifting cost per Mcf                                      $     0.63       $     0.64        $    (0.01)         (2%)
 DD&A                                                              $  294,000       $  155,000        $  139,000          90%
 DD&A rate per Mcf volumes sold                                    $     0.39       $     0.31        $     0.08          26%
</TABLE>



Revenues and Volumes

Gas volumes sold domestically increased 161% and oil volumes sold domestically
increased by 108%. Both increases resulted from an increase in production from
existing producing wells and the addition of two new producing wells. Domestic
operating revenue, however, increased by only 23% due to significant declines in
both oil and gas prices.

Gas volumes sold in Australia increased 55% due to increased gas sales from
existing wells, new wells drilled and an increase in gas deliveries under the
Energex #2 contract. Gas revenues in Australia, increased by 75% due to an
increase in the average sales price received and to favorable exchange rates.

                                       13
<PAGE>

In natural gas production operations, joint owners may sell more or less than
the production volumes to which they are entitled based on their revenue
ownership interest. The joint operating agreement on the Comet Ridge project
includes gas balancing provisions to govern production allocations in this
situation. The Company records a natural gas imbalance in other liabilities if
its excess takes of natural gas exceed its remaining proved reserves for the
property. As of March 31, 2002, the Company had taken and sold more than its
share of natural gas volumes produced from the Comet Ridge project, and was
overproduced by approximately 886,000 Mcf. Based on the average price of $1.16
per Mcf received during 2002 from these sales, this represents $1,028,000 in gas
revenues. No liability has been recorded for the excess volumes taken as they do
not exceed the Company's share of remaining proved reserves. Under the terms of
the gas balancing agreement, the Company may be required to reduce the monthly
volumes it delivers by up to 50% in order to enable underproduced parties to
take more than their share of the gas and cure the imbalance. If the imbalance
were to be corrected over a relatively short term, it would adversely affect
revenues and cash flows during that period.

Costs and Expenses

The 23% decrease in domestic operating expenses was due to the Company's reduced
operating interest in the Hanna Basin project. Operating expenses in Australia
increased 52% due to an increase in the number of producing wells and increased
costs associated with processing and transporting increasing gas volumes. The
lifting cost per Mcf, however, has declined as sales volumes increase.

General and administrative expenses for the first quarter of 2002 increased 58%
when compared to the quarter ended March 31, 2001 due primarily to increases in
legal expense relating to the Tri-Star litigation and also to compensation
expense.

Domestic DD&A expense increased 135% due to increased sales volumes in the U.S.
In Australia, DD&A expense increased 90% due to increasing sales volumes and
increases in the DD&A cost base related to expected future drilling costs.

Other Income (Expense)

The Company recorded other income of $70,000 in the first quarter of 2002 for
royalty payments received as a result of a court settlement. The royalties
related to a domestic property the Company sold in fiscal 2000.

Interest expense increased to $632,000 from $461,000, due to deferred loan costs
being amortized for the full three months in the first quarter 2002 versus one
month in the first quarter of 2001.

The foreign exchange gain in the first quarter of 2002 and foreign exchange loss
in the first quarter of 2001 were recognized for the effect of fluctuations in
the U.S. dollar and Australian dollar exchange rate on transactions related to
the Company's operations in Australia.

Income Taxes

The Company recognized no income tax benefit for its loss in 2002 or 2001. With
the sale of a majority of the Company's U.S. producing properties in fiscal 2000
and its history of losses, management believes that sufficient uncertainty
exists regarding the realizability of its net deferred tax asset. It therefore
recorded a valuation allowance to offset the entire deferred tax asset for both
2002 and 2001.

                                       14
<PAGE>

                           PART II - OTHER INFORMATION

Item 1.  Legal Proceedings

         See Note 5 to the Consolidated Financial Statements under Part I -
         Item 1.

Item 2.  Changes in Securities and Use of Proceeds

         None

Item 3.  Defaults Upon Senior Securities

         None

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

         None

Item 5.  Other Information

         None

Item 6.  Exhibits and Reports on Form 8-K

         (a)    Exhibits:

                Filed in Part I

                    11.  Computation of per share earnings, filed herewith as
                         Note 4 to the Consolidated Financial Statements.

                Filed in Part II

                    4.74 Promissory Note dated March 4, 2002, in the amount of
                         $2,500,000 issued by Registrant to Slough Estates USA
                         Inc., filed herewith.

                   10.84 Warrant to Purchase the Registrant's common stock
                         dated March 8, 2002, issued to Richard A. Barber, filed
                         herewith.

                The other material contracts of the Company are incorporated
                herein by reference from the exhibit list in the Company's
                Annual Report on Form 10-KSB for the year ended December 31,
                2001.

          (b)   Reports on Form 8-K:

                None

                                       15
<PAGE>

                                   SIGNATURES

Pursuant to the requirements 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.

                               Tipperary Corporation
                               ----------------------------------------------
                               Registrant

Date:    May 15, 2002      By:          /s/ David L. Bradshaw
                               ----------------------------------------------
                                        David L. Bradshaw, President, Chief
                                        Executive Officer and Chairman of the
                                        Board of Directors




Date:    May 15, 2002      By:          /s/ Lisa S. Wilson
                               ----------------------------------------------
                                        Lisa S. Wilson, Chief Financial Officer
                                        and Principal Accounting Officer

                                       16