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   June 30, 2002
OR
o	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 (State or other jurisdiction of incorporation or organization)	75-1236955 (I.R.S. Employer Identification No.)
	633 Seventeenth Street, Suite 1550 Denver, Colorado (Address of principal executive offices)	80202 (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 o

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 August 14, 2002
Common Stock, $.02 par value	39,221,489 shares

TIPPERARY CORPORATION AND SUBSIDIARIES

Index to Form 10-QSB

			Page No.
PART I.	FINANCIAL INFORMATION (UNAUDITED)
	Item 1.	Financial Statements
		Consolidated Balance Sheets June 30, 2002 and December 31, 2001	1
		Consolidated Statements of Operations three months and six months ended June 30, 2002 and 2001	2
		Consolidated Statements of Cash Flows six months ended June 30, 2002 and 2001	3
		Notes to Consolidated Financial Statements	4-9
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	10-18
PART II.	OTHER INFORMATION
	Item 1.	Legal Proceedings	19
	Item 2.	Changes in Securities	19
	Item 3.	Defaults Upon Senior Securities	19
	Item 4.	Submission of Matters to a Vote of Security Holders	19
	Item 5.	Other Information	19
	Item 6.	Reports on Form 8-K Exhibits and	20
SIGNATURES			21

PART I - FINANCIAL INFORMATION

Item 1.  Financial Statements

TIPPERARY CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
(in thousands)
(unaudited)

	June 30			December 31
	2002			2001
ASSETS
Current assets:
Cash and cash equivalents	$	1,572		$	9,415
Restricted cash		483			1,312
Receivables		3,018			2,518
Prepaid drilling costs		–			2,821
Other current assets		118			293
Total current assets		5,191			16,359
Property, plant and equipment, at cost:
Oil and gas properties, full cost method		66,510			74,005
Other property and equipment		3,987			3,903
		70,497			77,908
Less accumulated depreciation, depletion and amortization		(3,927	)		(23,486	)
Property, plant and equipment, net		66,570			54,422
Deferred loan costs		6,086			6,726
Other noncurrent assets		55			20
	$	77,902		$	77,527
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	780			2,231
Accounts payable		1,415			4,022
Accrued liabilities		1,413			1,004
Royalties payable		133			234
Total current liabilities		3,741			7,491
Long-term debt, net of current portion		18,434			12,183
Minority interest		673			734
Commitments and contingencies (Note 5)
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; 39,231,087 shares issued and 39,221,489
outstanding at June 30, 2002 and 38,981,087 shares issued
and 38,971,489 shares outstanding at December 31, 2001		785			780
Capital in excess of par value		149,949			149,499
Accumulated deficit		(95,655	)		(93,135	)
Treasury stock, at cost; 9,598 shares		(25	)		(25	)
Total stockholders’ equity		55,054			57,119
	$	77,902		$	77,527

See accompanying notes to consolidated financial statements

1

TIPPERARY CORPORATION AND SUBSIDIARIES
Consolidated Statements of Operations
(in thousands, except per share data)
(unaudited)

	Three months ended						Six months ended
	June 30						June 30
	2002			2001			2002			2001
Revenues	$	1,252		$	772		$	2,604		$	1,641
Costs and expenses:
Operating		716			656			1,308			1,118
Depreciation, depletion and amortization		412			215			835			425
Gain on sale of assets		(766	)		–			(766	)		–
General and administrative		1,039			1,067			2,586			2,044
Total costs and expenses		1,401			1,938			3,963			3,587
Operating loss		(149	)		(1,166	)		(1,359	)		(1,946	)
Other income (expense):
Other income		–			–			70			–
Interest income		32			37			48			84
Interest expense		(762	)		(782	)		(1,394	)		(1,243	)
Foreign currency exchange gain (loss)		31			60			54			(32	)
Total other expense		(699	)		(685	)		(1,222	)		(1,191	)
Loss before income taxes		(848	)		(1,851	)		(2,581	)		(3,137	)
Income tax expense (benefit)		–			(1	)		–			(1	)
Net loss before minority interest		(848	)		(1,850	)		(2,581	)		(3,136	)
Minority interest in loss (income) of subsidiary		(89	)		53			61			144
Net loss	$	(937	)	$	(1,797	)	$	(2,520	)	$	(2,992	)
Net loss per share
Basic and diluted	$	(.02	)	$	(.07	)	$	(.06	)	$	(.12	)
Weighted average shares outstanding
Basic and diluted		39,221			24,547			39,147			24,510

See accompanying notes to consolidated financial statements.

2

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

	Six months ended
	June 30
	2002			2001
Cash flows from operating activities:
Net loss	$	(2,520	)	$	(2,992	)
Adjustments to reconcile net loss to net cash
used in operating activities:
Depreciation, depletion and amortization		835			425
Amortization of deferred loan costs		798			519
Compensatory warrants granted		5			–
Minority interest in loss of subsidiary		(61	)		(144	)
Gain on sale of assets		(766	)		–
Change in assets and liabilities:
Decrease (increase) in receivables		(533	)		239
Decrease in prepaid drilling costs and other current assets		175			454
Increase (decrease) in accounts payable and accrued liabilities		(252	)		(619	)
(Decrease) increase in royalties payable		(101	)		12
Net cash used in operating activities		(2,420	)		(2,106	)
Cash flows from investing activities:
Proceeds from asset sales		5,329			1,930
Capital expenditures		(16,223	)		(8,937	)
Net cash used in investing activities		(10,894	)		(7,007	)
Cash flows from financing activities:
Proceeds from borrowings		5,000			15,500
Principal repayments		(200	)		(4,407	)
Decrease (increase) in restricted cash		829			(176	)
Payments for deferred loan costs		(158	)		(837	)
Net cash provided by financing activities		5,471			10,080
Net increase (decrease) in cash and cash equivalents		(7,843	)		967
Cash and cash equivalents at beginning of period		9,415			1,579
Cash and cash equivalents at end of period	$	1,572		$	2,546
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest	$	951		$	862
Income taxes	$	–		$	–
Non-cash investing and financing activities:
Issuance of stock to acquire assets	$	450		$	1,688
Net decrease in payables for capital expenditures	$	(2,865	)	$	–

See accompanying notes to consolidated financial statements.

3

TIPPERARY CORPORATION AND SUBSIDIARIES
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 June 30, 2002, and the results of its operations for the three-month and six-month periods ended June 30, 2002 and 2001 and its cash flows for the six-month periods ended June 30, 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”). 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 June 2002, the Financial Accounting Standards Board (“FASB”) issued SFAS 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS 146 is effective for exit or disposal activities that are initiated after December 31, 2002. This Statement addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force (EITF) Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” The Company does not believe that SFAS 146 will have a material impact on its results of operations or financial position.

In April 2002, the 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 results of operations.

In August 2001, the 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.

4

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

Disposition of Oil and Gas Properties

Under the full cost method of accounting for oil and gas exploration and production, sales of oil and gas properties are accounted for as adjustments of capitalized costs, with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. If a gain or loss is to be recognized, the cost of the property sold is an allocation of the cost center’s total costs based on the relative fair market value of the property sold compared to the estimated fair market value of the properties retained when there are substantial economic differences between the property sold and the properties retained. On May 24, 2002, the Company sold its remaining U.S. proved producing property, retaining only unproved properties in the U.S. cost center, and it recognized a gain of $766,000 on the sale. See Note 7.

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. For gas imbalances, the Company recognizes overproduction as a reduction in proved reserves and recognizes underproduction as an increase in proved reserves. 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 June 30, 2002, the Company had taken and sold 772,000 Mcf more than its entitled share of natural gas volumes produced from the Comet Ridge project in Queensland, Australia. Based on an average price of $1.19 per Mcf for Company sales of Comet Ridge gas during 2002, the Company’s 772,000 Mcf gas imbalance at June 30, 2002 represents $772,000 in gas revenues, net of the 10% Queensland royalty and a 6% overriding royalty described in Note 3. Other owners in the Comet Ridge project have limited rights under the joint operating agreement to cure this gas imbalance in the future by selling more gas than their entitled share of a month’s production and having the Company sell less gas, but not less than 50% of its entitled share for the month. At current sales levels, under current contracts, certain underproduced owner(s) are able, but have not elected, to substantially cure the gas imbalance over a period of six to twelve months.

Liquidity and Operations

The Company anticipates funding operations and capital expenditures for the remainder of 2002 using (a) cash on hand at June 30, (b) gas revenues and, (c) $5 million of additional borrowing from TCW Asset Management Company (“TCW”) funded on August 2, 2002 (see Note 3). 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 additional sources of capital. The Company intends to seek additional debt financing for further development of the Comet Ridge project and will continue to seek industry partners in domestic exploration projects. The Company expects to generate cash to reduce its investment in individual projects through the sale of partial interests to industry partners. 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.

5

NOTE 2 - RELATED PARTY TRANSACTIONS

Slough, the Company’s largest (61.3% at June 30, 2002) shareholder, has advanced the Company $2,500,000 for the purchase of a drilling rig which the Company 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 June 30, 2002, the balance due on this loan was $2,225,000. The drilling contractor has an option to buy the drilling rig from the Company prior to June 30, 2003, for a cash payment equal to the loan balance when the option is exercised. The sales proceeds would be used to retire the debt associated with the rig.

NOTE 3 - LONG-TERM DEBT - UNRELATED PARTY

The Company is a party to an amended and restated Credit Agreement with TCW Asset Management Company (“TCW”), with an initial borrowing facility of up to $17 million. By April 2002, the Company had borrowed the full $17 million for development of the Comet Ridge project. On July 31, 2002, the Credit Agreement was amended to raise the borrowing facility to $22 million, and TCW advanced on August 2, 2002 the additional $5 million for Comet Ridge development. The obligation to repay the 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 on the Company’s Comet Ridge gas sales revenues before deducting other costs and royalties.

After the loan is paid 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 (after certain gas delivery costs) from the then proved reserves, discounted at a nominal 15% annual rate compounded quarterly which is an effective rate of 15.865% per annum. After the loan is paid in full, the Company has the right to purchase the royalty interest from TCW for the sum of (a) the net present value of the royalty interest’s share of future net revenues (after certain gas delivery costs) from the then proved reserves, discounted at 15.865% per annum plus (b) such additional amount, if any, to provide TCW a 15.865% internal rate of return without consideration of the value in (a).

Principal payments are due quarterly beginning in March 2005 equal to 5.3875% of the unpaid principal balance, increasing to 6.59% in March 2006, decreasing to 5.91% in March 2007 and increasing to 7.09% in March 2008. The outstanding principal balance is due in full on December 31, 2008. If the Company fails to make principal payments as required by the amended Credit Agreement, TCW may require all obligations to be immediately due and payable. The amended Credit Agreement requires that TOGA maintain working capital of at least $500,000.

Upon 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 June 30, 2002 also include approximately $1,346,000 of other costs incurred to obtain the TCW financing, which are likewise being amortized as interest expense over the life of the loan.

6

NOTE 4 - EARNINGS (LOSS) PER SHARE

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

	Three months ended						Six months ended
	June 30						June 30
	2002			2001			2002			2001
Numerator:
Net loss	$	(937	)	$	(1,797	)	$	(2,520	)	$	(2,992	)
Denominator:
Weighted average shares outstanding		39,221			24,547			39,147			24,510
Effect of dilutive securities:
Assumed conversion of dilutive options and warrants		–			–			–			–
Weighted average shares and dilutive potential common shares		39,221			24,547			39,147			24,510
Basic and diluted loss per share	$	(.02	)	$	(.07	)	$	(.06	)	$	(.12	)
Number of shares of potentially dilutive common stock from the      exercise of options and warrants not included in EPS that would        have been antidilutive		50			864			50			1,029
Total common stock and warrants that could potentially dilute basic      EPS in future periods		3,556			3,529			3,556			3,529

NOTE 5 - COMMITMENTS AND CONTINGENCIES

The Company, TOGA and two unaffiliated working interest owners are plaintiffs in a lawsuit filed in 1998, styled Tipperary Corporation and Tipperary Oil & Gas (Australia) Pty Ltd v. Tri-Star Petroleum Company, James H. Butler, Sr., and James H. Butler, Jr., Cause No. CV42,265, District Court of Midland County, Texas involving the Comet Ridge project. The plaintiffs allege, among other matters, that Tri-Star and/or the individual defendants failed to operate the project in a good and workmanlike manner and committed various other breaches of a joint operating contract, breached a previous mediation agreement, committed certain breaches of fiduciary and other duties owed to the plaintiffs, and committed fraud in connection with the project. Tri-Star answered the allegations, and filed a counterclaim alleging tortious interference with the contracts, with the authority to prospect covering the project and with contractual relationships with vendors; commercial disparagement; foreclosure of operator’s lien and alternatively forfeiture of undeveloped acreage; unjust enrichment and declaratory relief. As of February 2001, the court enjoined Tri-Star from asserting any forfeiture claims based upon events prior to that date. In March 2002, the court entered its Writ of Temporary Injunction (the “Injunction”) 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 Injunction provided that TOGA take over operations of the project on March 22, 2002, and TOGA took over operations on that date. Tri-Star appealed the Injunction and such appeal is pending in the Texas Eighth Court of Appeals. Primary briefs have been filed by the parties, but the Court of Appeals has not yet scheduled oral argument.

An evidentiary hearing relating to the existing Mediation Agreement between the parties and the obligation of the parties to arbitrate audit disputes was conducted in late April 2002. In June 2002, the Court ruled that the arbitration provisions of the Mediation Agreement are unenforceable, and the Court did not refer any issues between the parties to arbitration. On July 10, 2002, Tri-Star filed a Notice of Accelerated Appeal of the order on arbitration issues, which will also be heard by the Texas Eighth Court of Appeals. No briefs have yet been filed. The pending appeals have delayed the trial on the merits, and a new trial date will not be set before the appellate cases are resolved. While the appeals will be heard on an expedited basis, it is not possible to predict the length of the appellate process.

7

Through June 30, 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. If the June 21, 2002 ruling on arbitration issues is upheld by the Court of Appeals, it is anticipated that the Court will return the funds to the Company. If the funds are returned, the Company will reduce its full cost pool for approximately $1 million of recovered capital costs and will record a gain of approximately $200,000 for recovered operating costs. If, and to the extent, funds are awarded to Tri-Star, the Company will not record an additional loss.

The Court may award additional damages to the Company as directed by the June 21, 2002 ruling.

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):

	United
	States		Australia		Total
Revenues for the three months ended June 30, 2002	$	209	$	1,043	$	1,252
Revenues for the three months ended June 30, 2001	$	162	$	610	$	772
Revenues for the six months ended June 30, 2002	$	564	$	2,040	$	2,604
Revenues for the six months ended June 30, 2001	$	483	$	1,158	$	1,641
Property, plant and equipment, net, at June 30, 2002	$	7,978	$	58,592	$	66,570
Property, plant and equipment, net, at June 30, 2001	$	7,058	$	40,973	$	48,031

NOTE 7 - ASSET SALES AND ACQUISITIONS

In fiscal 2000, the Company announced its plan to divest of all its domestic producing assets. On May 24, 2002, the Company sold all of its undivided interests in the West Buna field in Jasper and Hardin counties, Texas to Delta Petroleum Corporation (“Delta”) for $4.1 million in cash. Following the sale, the Company has no domestic producing assets, but does own interests in several unevaluated properties, some currently under evaluation. The Company reported total natural gas equivalent proved reserves of approximately 4.3 billion cubic feet and a present value, discounted at 10%, of approximately $5.8 million for the Texas property as of December 31, 2001. The Company recognized a gain of $766,000 on the sale.

On May 24, 2002, the Company acquired for $5.55 million Delta’s 5% interest in the Comet Ridge project in Australia and an option to purchase Delta’s interests of 2.5% or less in each of six other Authority to Prospect areas that have no proved reserves. The purchase price included $4.8 million in cash, $300,000 in assumed obligations, and 250,000 restricted shares of the Company’s common stock valued at $450,000. This acquisition has increased the Company’s total capital-bearing interest in the Comet Ridge project from 65% to 70%.

On June 3, 2002, for approximately $2.3 million in cash, the Company acquired from other non-affiliated private parties four separate interests in the Comet Ridge project, which increased the Company’s total capital-bearing interest in the Comet Ridge project from 70% to 73%.

8

NOTE 8 - PROPERTY, PLANT AND EQUIPMENT

A summary of property, plant and equipment follows:

	June 30			December 31
	2002			2001
Evaluated oil and gas properties:
Evaluated Australian properties		56,253			42,381
Evaluated domestic properties		–			23,511
Unevaluated oil and gas properties:
Unevaluated Australian properties	$	2,427		$	2,340
Unevaluated domestic properties		7,830			5,773
Oil and gas properties		66,510			74,005
Other property and equipment		3,987			3,903
		70,497			77,908
Less accumulated depreciation and amortization		(3,927	)		(23,486	)
Property, plant and equipment, net	$	66,570		$	54,422

As described in Note 7, the Company has completed the divestiture of all domestic producing properties. As of June 30, 2002, the Company has eliminated from its balance sheet $20.4 million in evaluated domestic property costs and $20.4 million in accumulated amortization associated with properties sold and abandoned in the past. The elimination of these costs and amortization amounts had no effect on the Company’s net property, plant and equipment balances.

9

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 have historically been conducted through its 90%-owned Australian subsidiary, Tipperary Oil & Gas (Australia) Pty Ltd (“TOGA”). TOGA owns an undivided interest in the Company’s primary producing property located in Queensland, Australia (the “Comet Ridge project”). In May and June of 2002 the Company acquired directly another 8% of undivided interests in the Comet Ridge project as described in Note 7. As of June 30, 2002, the Company and its subsidiaries own a 73% undivided interest in the Comet Ridge project. This project comprises approximately 964,000 acres in the Bowen Basin and includes 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$5.8 million net to the Company’s interest. The Company expects to satisfy its portion of the expenditure requirement through October 31, 2002 with its recently-proposed seven-well exploratory drilling program, which commenced in June 2002. The estimated cost of this drilling program is $4.7 million, of which the Company’s share is approximately $3.4 million. The Company will fund its share of these costs primarily with borrowings from TCW. The TCW debt facility is discussed below and in Note 3 to the Consolidated Financial Statements.

Through July 31, 2002, a total of 61 wells have been drilled on the Comet Ridge project including the 20-well development drilling program discussed below. There are 47 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 that supplies a compressor station feeding into a regulated gas pipeline. The remaining 28 producing wells are either being dewatered or are shut in pending connection. Production from the Comet Ridge wells currently totals approximately 23 million cubic feet (“MMcf”) of gas per day, of which approximately 17 MMcf is being sold. The gas not being sold is either being flared at the wellhead (4 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 was recently completed. The Company is currently selling gas from two wells in the 20-well development drilling program and expects to have the remaining gas producing

10

wells in this program connected and selling gas by November 2002. The Company has funded its share of the drilling costs with financing received under the TCW borrowing facility. In July 2002, the Company began a 2-well drilling program to meet expenditure requirements on two of its petroleum leases within ATP 526, with an estimated cost of approximately $1.0 million, of which the Company’s share is $750,000. The Company expects to substantially fund this drilling program with a portion of the $5 million received from TCW on August 2, 2002.

In 2001, the Company entered into a gas sales agreement to supply up to 260 bcf of gas to Queensland Fertilizer Assets Limited (“QFAL”). The gas is to be consumed over a 20-year period beginning in mid 2004 by a fertilizer plant QFAL plans to construct in southeastern Queensland. The agreement, as amended in May 2002, provides that QFAL has until September 1, 2002 to obtain commitments to finance construction of the fertilizer plant. Should QFAL be unable to obtain the financing commitments by September 1 and the Company elect not to extend the agreement, the Company would be released from the gas supply commitment and could seek to sell its gas to other parties. There is no assurance that the Company will be able to obtain other gas contracts commencing in 2004 for quantities or prices that equal or exceed the levels under the QFAL contract.

On March 22, 2002, the Company assumed operation of the Comet Ridge project pursuant to orders issued by the Court in Midland County, Texas. The Court’s ruling granted the Company and others 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.

In addition to the interest in the Comet Ridge property, TOGA holds interests in other exploration permits in Queensland which cover a total of approximately 1.2 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 coalbed methane 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 around one of the exploratory wells in early May 2002. The Company will be evaluating the gas and water production from these wells during 2002 in order to determine whether the gas production will be economically viable. During the third and fourth quarters of 2002 the Company plans to drill an additional four exploratory coalbed methane wells around the other exploratory well on the Lay Creek project at a net cost of approximately $950,000.

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 $1,798,000 for costs incurred to drill and complete the two wells in 2001 and to drill the four well pilot drilling program in the first half of 2002, leaving a balance as of June 30, 2002 of $202,000 due the Company on or before October 4, 2002. The Company expects to realize the remaining balance of this receivable during the third quarter of 2002 through Koch’s payment of the Company’s share of drilling and completion costs.

In February 2002, the Company 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 also agreed to pay one-half of the Company’s drilling costs to an agreed casing point for its 40% retained interest. The purchaser, which is serving as operator, is currently conducting exploratory operations on this prospect. An initial well has been drilled and cased and is currently being evaluated. The project comprises approximately 35,000 acres.

11

In addition to the aforementioned projects, the Company has leased approximately 279,000 acres in other areas of Colorado as of June 30, 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 discontinue participation in this project, the associated costs were included in the amortization base beginning with the second quarter of 2002. In May 2002, the operator shut in all wells and is evaluating the viability of the project.

In fiscal 2000, the Company announced its plan to divest of all its domestic producing assets. On May 24, 2002, the Company sold for $4.1 million in cash all of the Company’s undivided interests in the West Buna field in Jasper and Hardin counties, Texas to Delta Petroleum Corporation (“Delta”). Following the sale, the Company has no domestic producing assets, but does own interests in several unevaluated properties, some currently under evaluation. The Company reported total natural gas equivalent proved reserves of approximately 4.3 billion cubic feet and a present value, discounted at 10%, of approximately $5.8 million for the Texas property as of December 31, 2001. The Company recognized a gain of $766,000 on the sale.

Financial Condition, Liquidity and Capital Resources

The Company anticipates funding operations and capital expenditures for the remainder of 2002 using (a) cash on hand at June 30, (b) gas revenues, and (c) $5 million of additional borrowing from TCW Asset Management Company (“TCW”) funded on August 2, 2002 (see Note 3). 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 additional sources of capital. The Company intends to seek additional debt financing for further development of the Comet Ridge project and will continue to seek industry partners in domestic exploration projects. The Company expects to generate cash to reduce its investment in individual projects through the sale of partial interests to industry partners. 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 $1,572,000 as of June 30, 2002, compared to $9,415,000 as of December 31, 2001. At June 30, 2002, the Company had working capital of $1,450,000 compared to working capital of $8,868,000 as of December 31, 2001. The Company’s working capital position was improved by $5 million upon receipt of TCW funds on August 2, 2002. Working capital includes restricted cash of $483,000 as of June 30, 2002 and $1,312,000 as of December 31, 2001. The restricted cash as of June 30, 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 six months ended June 30, 2002, cash flows were provided by existing cash balances and $5 million of borrowings received from TCW. Available cash was used to fund capital expenditures and operating activities.

Net cash used by operating activities was $2,420,000 during the six months ended June 30, 2002 compared to $2,106,000 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 US 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 six months ended June 30, 2002, the Company made capital expenditures of $16,223,000, including $7,527,000 for Comet Ridge acquisitions. Capital expenditures also included $6,612,000 for drilling and completion costs on the Comet Ridge project, $1,049,000 for domestic leasehold cost acquisitions, $311,000 for Nine Mile exploratory costs and $89,000 for other various capital spending in Australia and

12

the United States. The Company’s share of costs on a four well pilot program in the Lay Creek project was $958,000, most of which had been reimbursed by Koch by June 30, 2002. Proceeds from asset sales of $5,329,000 during the six months ended June 30, 2002 included $4,100,000 from the sale of the West Buna properties, $594,000 received from the sale of a 50% interest in the Nine Mile prospect in Colorado and $635,000 in reimbursed Lay Creek drilling costs under the terms of the 2001 purchase and sale agreement with Koch . The Company received approximately $2 million from Koch at closing and has received or billed $1,798,000 for costs related to the wells recently drilled at Lay Creek. Approximately $202,000, 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 six months ended June 30, 2001, the Company had net receipts of $10,080,000 from financing activities, which included borrowings of $8,500,000 from TCW and $7,000,000 from Slough, offset by principal repayments to Slough of $4,407,000 and $837,000 in costs associated with the TCW loan. Capital expenditures of $8,937,000 included $2,480,000 for the purchase of a drilling rig which has been leased to a drilling contractor in Queensland, Australia (see Note 2), $1,661,000 for acreage acquisitions in Colorado, $3,028,000 for drilling, completion and other costs on the Comet Ridge project and $276,000 for drilling and completion costs on the Hanna Basin project. In June 2001, the Company acquired an additional 2.5% capital-bearing interest in the Comet Ridge project. The total purchase price of $1,688,000 was paid to the seller with the issuance of 675,000 shares of the Company’s restricted common stock valued at $2.50 per share.

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 $4,407,000, 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 $1,353,000 was deposited into a collateral 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 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 amortized as interest expense over the life of the loan. As of June 30, 2002, deferred loan costs also include approximately $1,346,000 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 $5 million under the facility. On July 31, 2002 the facility was increased to $22 million, and the company borrowed an additional $5 million on August 2, 2002.

After the loan is paid 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 (after certain gas delivery costs) from the then proved reserves, discounted at a nominal 15% annual rate compounded quarterly, i.e., an effective rate of 15.865% per annum. After the loan is paid in full, the Company has the right to purchase the royalty interest from TCW for the sum of (a) the net present value of the royalty interest’s share of future net revenues (after certain gas delivery costs) from the then proved reserves, discounted at 15.865% per annum plus (b) such additional amount, if any, to provide TCW a 15.865% internal rate of return without consideration of the value in (a).

Principal payments are due quarterly beginning in March 2005 equal to 5.3875% of the unpaid principal balance, increasing to 6.59% in March 2006, decreasing to 5.91% in March 2007 and increasing to 7.09% in March 2008. The outstanding principal balance is due in full on December 31, 2008. If the Company fails to make principal payments as required by the amended Credit Agreement, TCW may require all obligations to be immediately due and payable. The amended Credit Agreement requires that TOGA maintain working capital of at least $500,000.

In January 2001, Slough, the Company’s largest (61.3% at June 30, 2002) shareholder, advanced the Company $2,500,000 for the purchase of a drilling rig which the Company 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 June 30, 2002, the balance due on this loan was $2,225,000. The drilling contractor has an option to buy the drilling rig from the Company prior to June 30, 2003, for a cash payment equal to the loan balance when the option is exercised. The sales proceeds would be used to retire the debt associated with the rig.

13

Results of Operations - Comparison of the Three Months Ended June 30, 2002 and 2001

The Company incurred a net loss of $937,000 for the three months ended June 30, 2002, compared to a net loss of $1,797,000 for the three months ended June 30, 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 June 30, 2002 with those of the prior year’s quarter.

	Three Months Ended
	June 30					Increase		%Increase
	2002		2001		(Decrease)			(%Decrease)
Worldwide operations:
Operating revenue	$	1,252,000	$	772,000	$	480,000			62%
Gas volumes (Mcf)		881,000		578,000		303,000			52%
Oil volumes (Bbls)		3,900		2,300		1,600			70%
Average gas price per Mcf	$	1.27	$	1.23	$	0.04			3%
Average oil price per Bbl	$	23.93	$	26.89	$	(2.96	)		(11%	)
Operating expenses	$	716,000	$	656,000	$	60,000			9%
Average lifting cost per Mcf equivalent (“Mcfe”)	$	0.79	$	1.12	$	(0.33	)		(29%	)
General and administrative	$	1,039,000	$	1,067,000	$	(28,000	)		(3%	)
Depreciation, depletion and amortization (“DD&A”)	$	412,000	$	215,000	$	197,000			92%
DD&A rate per Mcfe volumes sold	$	0.46	$	0.36	$	0.10			28%
Interest expense	$	762,000	$	782,000	$	(20,000	)		(3%	)
Foreign currency exchange gain (loss)	$	31,000	$	60,000	$	(29,000	)		(48%	)
Domestic operations:
Operating revenue	$	209,000	$	162,000	$	47,000			29%
Gas volumes (Mcf)		26,000		22,000		4,000			18%
Oil volumes (Bbls)		3,900		2,300		1,600			70%
Average gas price per Mcf	$	3.03	$	4.61	$	(1.58	)		(34%	)
Average oil price per Bbl	$	23.93	$	26.89	$	(2.96	)		(11%	)
Operating expenses	$	143,000	$	154,000	$	(11,000	)		(7%	)
Average lifting cost per Mcfe	$	2.89	$	4.57	$	(1.68	)		(37%	)
DD&A	$	58,000	$	47,000	$	11,000			23%
DD&A rate per Mcfe volumes sold	$	1.17	$	1.33	$	(.16	)		(12%	)
Australia operations:
Operating revenue	$	1,043,000	$	610,000	$	433,000			71%
Gas volumes (Mcf)		855,000		556,000		299,000			54%
Average gas price per Mcf	$	1.22	$	1.10	$	0.12			11%
Operating expenses	$	573,000	$	502,000	$	71,000			14%
Average lifting cost per Mcf	$	0.67	$	0.90	$	(0.23	)		(26%	)
DD&A	$	354,000	$	168,000	$	186,000			111%
DD&A rate per Mcf volumes sold	$	0.41	$	0.30	$	0.11			37%

14

Revenues and Volumes

Gas volumes sold domestically increased 18% and oil volumes sold domestically increased by 70%. Both increases resulted from an increase in production from existing producing wells and the addition of two new producing wells. This increase was partially offset by the loss of all domestic production following the sale of the Company’s West Buna field, in late May 2002. Domestic operating revenue, however, increased by only 29% due to significant declines in both oil and gas prices.

Gas volumes sold in Australia increased 54% due to increased gas sales from existing wells, new wells drilled and an increase in gas deliveries. Gas revenues in Australia increased by 71% due to the increase in sales volumes, an increase in the average sales price received and to changes in exchange rates.

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. For gas imbalances, the Company recognizes overproduction as a reduction in proved reserves and recognizes underproduction as an increase in proved reserves. 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 June 30, 2002, the Company had taken and sold 772,000 Mcf more than its entitled share of natural gas volumes produced from the Comet Ridge project in Queensland, Australia. Based on an average price of $1.19 per Mcf for Company sales of Comet Ridge gas during 2002, the Company’s 772,000 Mcf gas imbalance at June 30, 2002 represents $772,000 in gas revenues, net of the 10% Queensland royalty and a 6% overriding royalty described in Note 3. Other owners in the Comet Ridge project have limited rights under the joint operating agreement to cure this gas imbalance in the future by selling more gas than their entitled share of a month’s production and having the Company sell less gas, but not less than 50% of its entitled share for the month. At current sales levels, under current contracts, certain underproduced owner(s) are able, but have not elected, to substantially cure the gas imbalance over a six-month period.

Costs and Expenses

The 7% decrease in domestic operating expenses was due to the Company’s reduced operating interest in the Hanna Basin project offset by costs associated with its new wells on the Lay Creek project. Operating expenses in Australia increased 14% 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 decreased 3% when compared to the three months ended June 30, 2001. The Company has experienced lower legal costs in the second quarter of 2002 which has contributed to the decrease in general and administrative expenses.

Domestic DD&A expense increased 23% due to increased sales volumes in the U.S. In Australia, DD&A expense increased 111% due to increasing sales volumes and increases in the DD&A cost base related to capital expenditures including acquisitions and expected future drilling costs. DD&A expense also increased as a result of a $58,000 upward adjustment to depreciation expense associated with the Soilmec drilling rig.

Other Income (Expense)

Interest expense decreased to $762,000 from $782,000, due to lower average principal balances offset by higher interest rates and TCW financing cost amortization over the three months ended June 30, 2002 as compared to the three months ended June 30, 2001.

The foreign exchange gains in the second quarter of 2002 and 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.

15

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.

Results of Operations - Comparison of the Six Months Ended June 30, 2002 and 2001

The Company incurred a net loss of $2,520,000 for the six months ended June 30, 2002, compared to a net loss of $2,992,000 for the six months ended June 30, 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 six months ended June 30, 2002 with those of the prior year’s six months.

	Six Months Ended
	June 30					Increase			% Increase
	2002		2001			(Decrease)			(% Decrease)
Worldwide operations:
Operating revenue	$	2,604,000	$	1,641,000		$	963,000			59	%
Gas volumes (Mcf)		1,700,000		1,091,000			609,000			56	%
Oil volumes (Bbls)		13,900		7,100			6,800			96	%
Average gas price per Mcf	$	1.29	$	1.32		$	(0.03	)		(2	%)
Average oil price per Bbl	$	21.14	$	27.88		$	(6.74	)		(24	%)
Operating expenses	$	1,308,000	$	1,118,000		$	190,000			17	%
Average lifting cost per Mcf equivalent (“Mcfe”)	$	0.73	$	1.00		$	(0.27	)		(27	%)
General and administrative	$	2,586,000	$	2,044,000		$	542,000			27	%
Depreciation, depletion and amortization (“DD&A”)	$	835,000	$	425,000		$	410,000			96	%
DD&A rate per Mcfe volumes sold	$	0.47	$	0.37		$	0.10			27	%
Interest expense	$	1,394,000	$	1,243,000		$	151,000			12	%
Foreign currency exchange gain (loss)	$	54,000	$	(32,000	)	$	86,000			N/	A
Domestic operations:
Operating revenue	$	564,000	$	483,000		$	81,000			17	%
Gas volumes (Mcf)		86,000		45,000			41,000			91	%
Oil volumes (Bbls)		13,900		7,100			6,800			96	%
Average gas price per Mcf	$	3.14	$	6.36		$	(3.22	)		(51	%)
Average oil price per Bbl	$	21.14	$	27.88		$	(6.74	)		(24	%)
Operating expenses	$	257,000	$	302,000		$	(45,000	)		(15	%)
Average lifting cost per Mcfe	$	1.52	$	3.62		$	(2.10	)		(58	%)
DD&A	$	187,000	$	102,000		$	85,000			83	%
DD&A rate per Mcfe volumes sold	$	1.10	$	1.17		$	(.07	)		(6	%)

16

	Six Months Ended
	June 30				Increase			% Increase
	2002		2001		(Decrease)			(% Decrease)
Australia operations:
Operating revenue	$	2,040,000	$	1,158,000	$	882,000			76	%
Gas volumes (Mcf)		1,614,000		1,046,000		568,000			54	%
Average gas price per Mcf	$	1.19	$	1.11	$	0.08			7	%
Operating expenses	$	1,051,000	$	816,000	$	235,000			29	%
Average lifting cost per Mcf	$	0.65	$	0.78	$	(0.13	)		(17	%)
DD&A	$	648,000	$	323,000	$	325,000			101	%
DD&A rate per Mcf volumes sold	$	0.40	$	0.31	$	0.09			29	%

Revenues and Volumes

Gas volumes sold domestically increased 91% and oil volumes sold domestically increased by 96%. Both increases resulted from an increase in production from existing producing wells and the addition of two new producing wells. This increase was partially offset by the loss of all domestic production following the sale of the Company’s West Buna field, in late May 2002. Domestic operating revenue, however, increased by only 17% due to significant declines in both oil and gas prices.

Gas volumes sold in Australia increased 54% due to increased gas sales from existing wells, new wells drilled and an increase in gas deliveries. Gas revenues in Australia increased by 76% due to the increase in sales volumes, an increase in the average sales price received and to changes in exchange rates.

Costs and Expenses

The 15% decrease in domestic operating expenses was due primarily to the Company’s reduced operating interest in the Hanna Basin project offset by costs associated with its new wells on the Lay Creek project. Operating expenses in Australia increased 29% 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 six months of 2002 increased 27% when compared to the six months ended June 30, 2001 due primarily to increases in legal expense relating to the Tri-Star litigation and also to increases in compensation expense, both experienced during the first quarter of 2002.

Domestic DD&A expense increased 83% due to increased sales volumes in the U.S. In Australia, DD&A expense increased 101% due to increasing sales volumes and increases in the DD&A cost base related to capital expenditures including acquisitions and expected future drilling costs. DD&A expense also increased as a result of a $58,000 upward adjustment to depreciation expense associated with the Soilmec rig.

Other Income (Expense)

Interest expense increased to $1,394,000 from $1,243,000, due to higher interest rates and TCW financing cost amortization offset by lower average principal balances over the six months ended June 30, 2002.

The foreign exchange gain in the first six months of 2002 and foreign exchange loss in the first six months 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.

17

Income Taxes

The Company recognized no income tax benefit for its loss in 2002 or 2001. With the sale of virtually all of the Company’s U.S. producing properties 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.

18

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
	In May 2002, the Company issued restricted common stock in addition to $4.8 million in cash to an unaffiliated third party for the acquisition of an additional 5% capital-bearing interest in the Comet Ridge coalbed methane project in Queensland, Australia. The restricted common stock issued was valued at $450,000 and was paid to the seller with the issuance of 250,000 shares, which had a value of $1.80 per share on the date the transaction closed.
	The offer and sale of the shares were not registered under the Securities Act of 1933 (“Securities Act”), but rather were made privately by the Company pursuant to the exemption from registration provided by Section 4(2) of the Securities Act. The purchaser of the common stock had full information concerning the business and affairs of the Company and acquired the shares for investment purposes. The certificates representing the securities issued bear a restrictive legend and stop transfer instructions have been entered prohibiting transfer of the securities except in compliance with applicable securities laws.
Item 3.	Defaults Upon Senior Securities
	None
Item 4.	Submission of Matters to a Vote of Security Holders
	The Company held its Annual Meeting of Shareholders on April 23, 2002, and proxies for such meeting were solicited pursuant to Regulation 14A adopted under the Securities Exchange Act of 1934. There was no solicitation in opposition to management’s nominees for directors as listed in the proxy statement and all such nominees were elected. The table below summarizes the voting results:

	Votes For	Votes Withheld
Kenneth L. Ancell	32,381,652	189,385
David L. Bradshaw	32,381,652	189,385
Eugene I. Davis	32,381,652	189,385
Douglas Kramer	32,364,265	206,772
Marshall D. Lees	32,381,652	189,385
Charles T. Maxwell	32,381,647	189,390
D. Leroy Sample	32,381,652	189,385

In addition, the shareholders ratified the following proposal:

A proposal to ratify the reappointment of PricewaterhouseCoopers LLP as the Company’s independent accountants for the year ended December 31, 2002;

For	Against	Abstain
32,488,922	72,525	9,520

Item 5.       Other Information

                  None

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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
		4.75	First Amendment to First Amended and Restated Credit Agreement among Tipperary Corporation as Borrower, Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077536871) as Guarantor, Tipperary Oil & Gas Corporation, Lenders party thereto and TCW Asset Management Company in the capacities described therein dated as of July 31, 2002, filed herewith.
		10.87	Amendment to Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (CAN 077536871) as Seller and Queensland Fertilizer Assets Limited (CAN 011062294) as Buyer, dated May 30, 2002, filed herewith.
		99.2	Certification of Chief Executive Officer of Tipperary Corporation Pursuant to 18 U.S.C. §1350, filed herewith.
		99.3	Certification of Chief Financial Officer of Tipperary Corporation Pursuant to 18 U.S.C. §1350, 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:
		On June 10, 2002 and as amended on August 13, 2002, the Company filed a Current Report on Form 8-K disclosing the purchase of a 5% interest in the Comet Ridge project from Delta Petroleum Corporation (“Delta”) and the sale of the West Buna field to Delta. The Current Report includes proforma information showing the effect of the Delta transactions.

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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:	August 14, 2002	By:	/s/ David L. Bradshaw
			David L. Bradshaw, President, Chief Executive Officer
			and Chairman of the Board of Directors
Date:	August 14, 2002	By:	/s/ Joseph B. Feiten
			Joseph B. Feiten, Chief Financial Officer and
			Principal Accounting Officer

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