Tipperary 10QSB 2002 Q3 Quarterly report (small business)

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

FORM 10-QSB

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

For the quarterly period ended September 30, 2002

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
Common Stock, $.02 par value

Outstanding at November 14, 2002
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 September 30, 2002 and December 31, 2001	1

		Consolidated Statements of Operations Three months and nine months ended September 30, 2002 and 2001	2

		Consolidated Statements of Cash Flows Nine months ended September 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

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	19

	Item 4.	Controls and Procedures	19



PART II.	OTHER INFORMATION

	Item 1.	Legal Proceedings	20

	Item 2.	Changes in Securities	20

	Item 3.	Defaults Upon Senior Securities	20

	Item 4.	Submission of Matters to a Vote of Security Holders	20

	Item 5.	Other Information	20

	Item 6.	Exhibits and Reports on Form 8-K	20



SIGNATURES	21

CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER	22-23

PART I – FINANCIAL INFORMATION

Item 1.

Financial Statements

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

	September 30 2002			December 31 2001


ASSETS
Current assets:
Cash and cash equivalents	$	3,480		$	9,415
Restricted cash		226			1,312
Receivables		1,657			2,518
Prepaid drilling costs		—			2,821
Other current assets		238			293

Total current assets		5,601			16,359


Property, plant and equipment, at cost:
Oil and gas properties, full cost method		72,390			74,005
Other property and equipment		4,024			3,903

		76,414			77,908

Less accumulated depreciation, depletion and amortization		(4,355	)		(23,486	)

Property, plant and equipment, net		72,059			54,422


Deferred loan costs		6,103			6,726
Other noncurrent assets		92			20

	$	83,855		$	77,527


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	2,110			2,231
Accounts payable		2,043			4,022
Accrued liabilities		2,480			1,004
Royalties payable		141			234

Total current liabilities		6,774			7,491


Long-term debt, net of current portion		22,989			12,183

Minority interest		662			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 September 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		149,951			149,499
Accumulated deficit		(97,281	)		(93,135	)
Treasury stock, at cost; 9,598 shares		(25	)		(25	)

Total stockholders’ equity		53,430			57,119

	$	83,855		$	77,527

See accompanying notes to consolidated financial statements.

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

	Three months ended September 30						Nine months ended September 30

	2002			2001			2002			2001


Revenues	$	1,092		$	881		$	3,696		$	2,522


Costs and expenses:
Operating		800			500			2,108			1,618
Depreciation, depletion and amortization		289			242			1,124			667
Gain on sale of assets		—			—			(766	)		—
Recovery of prepaid drilling costs		(282	)		—			(282	)		—
General and administrative		1,106			1,029			3,692			3,073


Total costs and expenses		1,913			1,771			5,876			5,358


Operating loss		(821	)		(890	)		(2,180	)		(2,836	)

Other income (expense):
Other income		—			—			70			—
Interest income		16			33			64			117
Interest expense		(797	)		(810	)		(2,191	)		(2,053	)
Foreign currency exchange gain (loss)		(35	)		8			19			(24	)


Total other expense		(816	)		(769	)		(2,038	)		(1,960	)


Loss before income taxes		(1,637	)		(1,659	)		(4,218	)		(4,796	)

Income tax benefit		—			—			—			(1	)


Net loss before minority interest		(1,637	)		(1,659	)		(4,218	)		(4,795	)

Minority interest in loss of subsidiary		11			69			72			213


Net loss	$	(1,626	)	$	(1,590	)	$	(4,146	)	$	(4,582	)


Net loss per share
Basic and diluted	$	(.04	)	$	(.06	)	$	(.11	)	$	(.19	)


Weighted average shares outstanding
Basic and diluted		39,221			25,148			39,090			24,725

See accompanying notes to consolidated financial statements.

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

	Nine months ended September 30

	2002			2001

Cash flows from operating activities:
Net loss	$	(4,146	)	$	(4,582	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		1,124			667
Amortization of deferred loan costs		1,118			910
Compensatory warrants granted		7			—
Minority interest in loss of subsidiary		(72	)		(213	)
Gain on sale of assets		(766	)		—
Change in assets and liabilities:
Decrease (increase) in receivables		54			176
Decrease in prepaid drilling costs and other current assets		55			198
Increase (decrease) in accounts payable and accrued liabilities		(70	)		(987	)
(Decrease) increase in royalties payable		(93	)		(45	)

Net cash used in operating activities		(2,789	)		(3,876	)


Cash flows from investing activities:
Proceeds from asset sales		5,623			2,340
Capital expenditures		(19,973	)		(12,337	)

Net cash used in investing activities		(14,350	)		(9,997	)


Cash flows from financing activities:
Proceeds from borrowings		11,000			20,000
Principal repayments		(315	)		(4,407	)
Decrease (increase) in restricted cash		1,086			(211	)
Payments for deferred loan costs		(567	)		(952	)

Net cash provided by financing activities		11,204			14,430


Net increase (decrease) in cash and cash equivalents		(5,935	)		557

Cash and cash equivalents at beginning of period		9,415			1,579


Cash and cash equivalents at end of period	$	3,480		$	2,136


Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest	$	1,502		$	1,123
Income taxes	$	—		$	—
Non-cash investing and financing activities:
Issuance of stock to acquire assets	$	450		$	1,688
Net increase in payables for capital expenditures				$	303

See accompanying notes to consolidated financial statements.

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 September 30, 2002, and the results of its operations for the three-month and nine-month periods ended September 30, 2002 and 2001 and its cash flows for the nine-month periods ended September 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 effect 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 adoption of SFAS 145 is not expected to have a material effect on the Company’s 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.

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 will be reported as A cumulative effect of a change in accounting principle. The Company will adopt SFAS 143 effective January 1, 2003. The Company is in the process of determining whether SFAS 143 will have a material effect 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 predominately unproved properties in the U.S. cost center. The Company recognized a gain of $766,000 on the sale. See Note 7 to the Consolidated Financial Statements.

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 uses the sales method, whereby overproduction is recognized as a reduction in proved reserves and underproduction is recognized 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 September 30, 2002, the Company had taken and sold 908,000 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 $1.20 per Mcf for Company sales of Comet Ridge gas during 2002, the Company’s 908,000 Mcf gas imbalance at September 30, 2002 represents $915,000 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, underproduced owners could 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 September 30, (b) gas revenues and, (c) a $2 million loan on October 30, 2002, of additional funding from Slough Estates USA, Inc. See Note 2 to the Consolidated Financial Statements. The Company is seeking additional long-term debt financing for further development of the Comet Ridge project and will continue to seek industry partners in domestic exploration projects. See Note 3 to the Consolidated Financial Statements. 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.

NOTE 2 - RELATED PARTY TRANSACTIONS

Slough Estates USA Inc. (“Slough”), the Company’s largest (60.74% at September 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 September 30, 2002, the balance due on this loan was $2,110,000. The drilling contractor has an option to buy the drilling rig from the Company prior to October 2005, for a cash payment equal to the loan balance when the option is exercised. See Note 9 to the Consolidated Financial Statements. In July 2002, Slough loaned $1 million to the Company. On October 30, 2002, Slough loaned an additional $2 million to the Company. These loans are for general corporate purposes, have an annual interest rate of 5.26% and are repayable on April 30, 2004.

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”), whereby the Company had borrowed $22 million as of September 30, 2002 for development of the Comet Ridge project. 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. The Company has met all debt covenants under the Credit Agreement with TCW.

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 September 30, 2002 also include approximately $1,683,000 of other costs incurred to obtain the TCW financing, which are likewise being amortized as interest expense over the life of the loan.

The Company has received a proposal from TCW to lend the Company an additional $25 million for further development of Comet Ridge in 2003. The Company is in discussions with several major banks to provide long-term development loans to the Company. No assurances can be made that the Company will be successful in its financing efforts.

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 September 30						Nine months ended September 30

	2002			2001			2002			2001

Numerator:
Net loss	$	(1,626	)	$	(1,590	)	$	(4,146	)		(4,582	)

Denominator:
Weighted average shares outstanding		39,221			25,148			39,090			24,725
Effect of dilutive securities:
Assumed conversion of dilutive options and warrants		—			—			—			—

Weighted average shares and dilutive potential common shares		39,221			25,148			39,090			24,725


Basic and diluted loss per share	$	(.04	)	$	(.06	)	$	(.11	)	$	(.19	)

Number of shares of potentially dilutive common stock from the exercise of options and warrants not included in EPS because they would have been antidilutive		82			236			60			712

Total common stock options and warrants that could potentially dilute basic EPS in future periods		3,488			3,517			3,488			3,517

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 District Court of Appeals. Primary briefs have been filed by the parties. The oral argument and submission date is November 19, 2002.

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 District Court of Appeals. Tri-Star’s primary brief has been filed, the Company’s responsive brief was filed on November 11, 2002, and oral argument has not yet been scheduled. 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.

Through September 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, such funds are awarded to Tri-Star, the Company will not record an additional loss.

In 2001 and 2000, the Company recognized write-offs of prepaid drilling costs of $900,000 and $557,000, respectively. Those write-offs related to uncollected receivables past due from Tri-Star. In September 2002, the Company recorded a gain of $282,000 for recovery of bad debt related to funds received from Tri-Star in excess of recorded receivables for unused, prepaid drilling costs.

The Company, as Operator of Comet Ridge, has requested that Tri-Star repay to other working interest owners $1.3 million of unused prepaid drilling costs. The Company’s share is $934,000 as of September 30, 2002, and the Company has recorded a fully reserved receivable, with no gain recognized until the receivable is paid or payment is reasonably certain.

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):

	Australia		United States			Total

Revenues for the three months ended September 30, 2002	$	1,227	$	(135	)	$	1,092
Revenues for the three months ended September 30, 2001	$	748	$	133		$	881

Revenues for the nine months ended September 30, 2002	$	3,267	$	429		$	3,696
Revenues for the nine months ended September 30, 2001	$	1,906	$	616		$	2,522

Property, plant and equipment, net, at September 30, 2002	$	62,909	$	9,150		$	72,059
Property, plant and equipment, net, at December 31, 2001	$	45,270	$	9,152		$	54,422

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 neglible domestic producing assets. 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 increased the Company’s total capital-bearing interest in the Comet Ridge project from 65% to 70%.

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

NOTE 8 – PROPERTY, PLANT AND EQUIPMENT

A summary of property, plant and equipment follows:

	September 30 2002			December 31 2001

Evaluated oil and gas properties:
Evaluated Australian properties	$	60,938		$	42,381
Evaluated domestic properties		441			23,511
Unevaluated oil and gas properties:
Unevaluated Australian properties		2,444			2,340
Unevaluated domestic properties		8,567			5,773

Oil and gas properties		72,390			74,005
Other property and equipment		4,024			3,903

		76,414			77,908
Less accumulated depreciation, depletion and amortization		(4,355	)		(23,486	)

Property, plant and equipment, net	$	72,059		$	54,422

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

NOTE 9 – SUBSEQUENT EVENT

On October 7, 2002, the Company entered into an agreement, with the unrelated drilling contractor that leases the Company’s drilling rig, to drill wells at Comet Ridge. The contractor is buying a similar rig for use at Comet Ridge, in addition to its existing lease of the Company’s rig. Under the agreement, the Company and the contractor will enter into a three-year drilling contract, subject to the terms of the Comet Ridge joint operating agreement. Wells drilled pursuant to the contract will be on a turnkey (fixed price) basis, consistent with terms received when the contractor uses the Company’s rig. For the contractor’s new rig, the Company has agreed to pay a stand-by rate of AUD $3,200 per day if the rig is available but standing by, awaiting Company requests for drilling. The Company has a three-year option to purchase the new rig from the contractor at a depreciated cost. The contractor’s option to purchase the Company’s rig was extended for the same three years, expiring in October 2005.

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”). At December 31, 2001, TOGA owned an undivided 65% 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 to the Consolidated Financial Statements. As of September 30, 2002, the Company and its subsidiaries owned a 73% undivided capital bearing 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 expenditure requirement through October 31, 2002 has been satisfied.

The ATP 526 renewal called for the working interest owners to relinquish approximately 25% of the 686,000 acres on November 1, 2002. The Queensland Minister for Natural Resources and Mines is considering a proposal to forego such relinquishment in exchange for an additional US$2.1 million (US$1.5 million net to the Company's interest) of exploration expenditures by November 1, 2003.

Comet Ridge Project

The table below summarizes field development progress on the Comet Ridge project. The Company anticipates approximately ten additional wells will be connected to the gathering system in the next three months, which will add approximately 3 MMcf per day to gross sales volumes.

Comet Ridge Operations Review:

	12/30/01		09/30/02		11/10/02


Well Status (Number of Wells)
Selling		18		19		26
Dewatering or Shut-in		16		30		23

Total Producing		34		49		49
Being Completed		13		16		18

Total Drilled		47		65		67


Gross Daily Volumes (Mmcf)
Sold		13		17		19
Flared		3		5		4
Used for Compression Fuel		2		2		2

Total Produced		18		24		25

A 20-well development drilling program on the Comet Ridge project was recently completed. The Company is currently selling gas from nine wells in the 20-well development drilling program and expects to have eight more gas producing wells in this program connected and selling gas by January 2003. The remaining three wells will require a period of dewatering before gas production is expected to occur. The Company has funded its share of the drilling costs with financing received under the TCW borrowing facility. During the quarter, the Company drilled two wells 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 approximately $730,000.

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 and September 2002, provides that QFAL has until January 1, 2003 to obtain commitments to finance construction of the fertilizer plant. Should QFAL be unable to obtain the financing commitments by January 1, 2003 and the Company elects not to extend the agreement, the Company would be released from the gas supply commitment. 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 on 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 the remainder of 2002 in

order to determine whether the gas production will be economically viable. During the third quarter of 2002, the Company drilled two additional exploratory coalbed methane wells offsetting the second exploratory well drilled in 2001 on the Lay Creek project. The Company plans to drill an additional two wells in the same pilot area and complete all four wells in the fourth quarter of 2002. Drilling and completion costs on the four wells are expected to total approximately $950,000, net to the Company’s interest.

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 $1,886,000 for costs incurred to drill and complete the two wells in 2001 and to drill wells during 2002, leaving a balance as of September 30, 2002 of $114,000 due the Company on or before October 4, 2002. The Company collected the entire $114,000 from Koch in early October 2002 and the Company will now be responsible for 50% of all future costs as set forth in the joint operating agreement.

In February 2002, the Company sold a 60% interest in the Nine Mile Prospect, a conventional oil and gas exploration prospect, which is also located in Moffat County, Colorado, to Elm Ridge Resources for approximately $595,000. The purchaser also agreed to pay one-half of the Company’s drilling costs to an agreed casing point on the first well for its 40% retained interest. The purchaser, which is serving as operator, is currently conducting exploratory operations on this prospect. On September 17, 2002, the Company announced the completion and initial testing of the Tipperary Ninemile Federal 34-1 in the prospect. This well was completed in the Almond formation at a depth of approximately 10,200 feet, with initial average flow rates of 2 million cubic feet per day of gas, 100 barrels per day of condensate and 250 barrels per day of water. The working interest owners are currently in discussions with pipeline companies regarding construction of a pipeline to deliver gas into the regional pipeline system. Tipperary and Elm Ridge are now drilling a second well to further test the Almond formation. Based upon its geologic interpretation, Tipperary management believes there may be potential for significant developmental drilling. The project comprises approximately 49,000 acres.

In addition to the aforementioned projects, the Company has leased approximately 279,000 acres in other areas of Colorado as of September 30, 2002. As it has with its other acreage, the Company will seek industry partners to join in the exploration of these prospective areas.

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 negligible domestic producing assets, but does own interests in exploratory and undeveloped properties as described above. 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 has funded operations for the nine months ended September 30, 2002, using primarily (a) $9.4 million of cash on hand at December 31, 2001, (b) a $5 million long-term loan from TCW in April 2002, (c) the aforementioned sale in May of the company’s interests in the West Buna field, and (d) a $5 million long-term loan from TCW in August 2002. See Note 3 to the Consolidated Financial Statements for further information on the TCW credit agreement.

The Company anticipates funding operations and capital expenditures for the remainder of 2002 using (a) cash on hand at September 30, (b) gas revenues, and (c) a $2 million loan on October 30, 2002, from Slough Estates USA, Inc. See Note 2 to the Consolidated Financial Statements. The Company is seeking additional long-term debt financing for further development of the Comet Ridge project and will continue to seek industry partners in domestic exploration projects. See Note 3 to the Consolidated Financial Statements. 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 $3,480,000 as of September 30, 2002, compared to $9,415,000 as of December 31, 2001. At September 30, 2002, the Company had negative working capital of $1,173,000 compared to working capital of $8,868,000 as of December 31, 2001. Working capital includes restricted cash of $226,000 as of September 30, 2002 and $1,312,000 as of December 31, 2001. Restricted cash consists of cash in collateral bank 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. During the nine months ended September 30, 2002, cash was primarily provided by (a) $9.4 million in cash on hand at December 31, 2001, (b) $10 million of borrowings received from TCW and (c) $1 million of borrowings received from Slough. Available cash was used to fund capital expenditures and operating activities.

Net cash used by operating activities was $2,789,000 during the nine months ended September 30, 2002 compared to $3,876,000 of cash used during the same period last year. The need to use cash for operations in both periods resulted primarily from the sale of most of the Company’s U.S. oil and gas properties after June 30, 2000. However, the loss in revenues from domestic properties has been partially offset by steadily increasing sales of natural gas in Australia. The Company anticipates positive cash flow from operations in the latter part of 2003.

The table below provides a detailed analysis of capital expenditures of $20 million during the nine months ended September 30, 2002.

Capital Expenditures Activity
(in thousands)

Australia:
Comet Ridge acquisitions	$	7,527
Comet Ridge drilling and completion		8,798
Comet Ridge facilities and equipment		782
Other		121

Domestic:
Leasehold acquisitions		1,170
Nine Mile exploratory		587
Lay Creek drilling and completion		922
Other		66


Total	$	19,973

Proceeds from asset sales of $5,623,000 during the nine months ended September 30, 2002 included $4,100,000 from the sale of the West Buna properties, $595,000 received from the sale of a 50% interest in the Nine Mile prospect in Colorado and $928,000 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 in May 2001and has received or billed $1,886,000 for costs related to the wells recently drilled at Lay Creek. The Company collected the remaining $114,000 from Koch in early October 2002 and the Company will now be responsible for 50% of all future costs as set forth in the joint operating agreement.

In January 2001, Slough 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 September 30, 2002, the balance due on this loan was $2,110,000. The drilling contractor has an option to buy the drilling rig from the Company prior to October 2005 for a cash payment equal to the loan balance when the option is exercised.

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

The Company incurred a net loss of $1,626,000 for the three months ended September 30, 2002, compared to a net loss of $1,590,000 for the three months ended September 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 September 30, 2002 with those of the prior year’s quarter.

	Three Months Ended September 30					Increase			% Increase

	2002			2001		(Decrease)			(% Decrease)


Worldwide operations:

Operating revenue	$	1,092,000		$	881,000	$	211,000			24%
Gas volumes (Mcf)		984,000			689,000		295,000			43%
Oil volumes (Bbls)		(2,900	)		2,600		(5,500	)		N/A
Average gas price per Mcf	$	1.19		$	1.19	$	—			0%
Average oil price per Bbl	$	26.21		$	24.10	$	2.11			9%
Operating expenses	$	800,000		$	500,000	$	300,000			60%
Average lifting cost per Mcf equivalent (“Mcfe”) sold	$	0.83		$	0.81	$	0.02			2%
General and administrative	$	1,106,000		$	1,029,000	$	77,000			7%
Depreciation, depletion and amortization (“DD&A”)	$	289,000		$	242,000	$	47,000			19%
DD&A rate per Mcfe volumes sold	$	0.30		$	0.34	$	(0.04	)		(12%	)
Interest expense	$	797,000		$	810,000	$	(13,000	)		(2%	)
Foreign currency exchange gain (loss)	$	(35,000	)	$	8,000	$	(43,000	)		N/A

Australia operations:

Operating revenue	$	1,227,000		$	748,000	$	479,000			64%
Gas volumes (Mcf)		1,002,000			666,000		336,000			50%
Average gas price per Mcf	$	1.22		$	1.12	$	0.10			9%
Operating expenses	$	723,000		$	368,000	$	355,000			96%
Average lifting cost per Mcf sold	$	0.72		$	0.55	$	0.17			31%
Oil and Gas property DD&A	$	271,000		$	146,000	$	125,000			86%
Other DD&A	$	6,000		$	45,000	$	(39,000	)		(87%	)
Oil and Gas DD&A rate per Mcf volumes sold	$	0.27		$	0.22	$	0.05			23%

Domestic operations:

Operating revenue	$	(135,000	)	$	133,000	$	(268,000	)		N/A
Gas volumes (Mcf)		(18,000	)		23,000		(41,000	)		N/A
Oil volumes (Bbls)		(2,900	)		2,600		(5,500	)		N/A
Average gas price per Mcf	$	3.28		$	3.06	$	0.22			7%
Average oil price per Bbl	$	26.21		$	24.10	$	2.11			9%
Operating expenses	$	77,000		$	132,000	$	(55,000	)		(42%	)
Average lifting cost per Mcfe sold		N/A		$	3.42		N/A			N/A
Oil and Gas property DD&A	$	—		$	39,000	$	(39,000	)		(100%	)
Other DD&A	$	12,000		$	12,000	$	—			0%
Oil and Gas DD&A rate per Mcfe volumes sold		N/A		$	1.01		N/A			N/A

Revenues and Sales Volumes

Gas volumes sold in Australia increased 50% due to increased gas sales from existing wells, new wells drilled and an increase in gas deliveries. Gas revenues in Australia increased by 64% 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 September 30, 2002, the Company had taken and sold 908,000 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 $1.20 per Mcf for Company sales of Comet Ridge gas during 2002, the Company’s 908,000 Mcf gas imbalance at September 30, 2002 represents $915,000 in gas revenues, net of the 10% Queensland royalty and a 6% overriding royalty described in Note 3 to the Consolidated Financial Statements. 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, underproduced owners could substantially cure the gas imbalance over a six to twelve month period.

During the third quarter of 2002 the Company had $135,000 of negative revenue representing the reimbursement of the West Buna field operator’s over distribution of revenue to the Company. The Company sold its West Buna interests in May 2002.

Costs and Expenses

Operating expenses in Australia increased 74% due to an increase in the number of producing wells and increased costs associated with processing and transporting increasing gas volumes. An additional 22% increase relates to unusually high diesel fuel tax rebates received in the three months ended September 2001. Australian Oil and Gas property DD&A expense increased 86% due primarily to increasing sales volumes.

Domestic operating expenses are largely attributable to the Lay Creek coal bed methane project where the initial wells are in the early dewatering phase. The decreases in domestic operating expenses were due to the Company’s reduced operating interest in the Hanna Basin project and the sale of the Company’s West Buna field. Domestic DD&A expense for the three months ended September 30, 2002, was primarily depreciation of office equipment. Domestic DD&A expenses decreased due to the aforementioned sale of the Company’s West Buna field.

General and administrative (“G&A”) expenses for the third quarter of 2002 increased 7% when compared to the three months ended September 30, 2001. The Company experienced higher compensation, consulting, insurance and travel costs in the third quarter of 2002 which contributed to the increase in general and administrative expenses. These increased G&A costs are primarily due to taking over operations on the Comet Ridge project in March 2002 and expanding the Company’s consolidated interests in Comet Ridge.

Other Income (Expense)

Interest expense decreased to $797,000 from $810,000, due to amortization of deferred loan costs over a longer loan repayment period for the long-term loan from TCW. See Note 3 to the Consolidated Financial Statements.

The foreign exchange loss and gain in the third quarter of 2002 and 2001, respectively, resulted from 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 losses 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 Nine Months Ended September 30, 2002 and 2001

The Company incurred a net loss of $4,146,000 for the nine months ended September 30, 2002, compared to a net loss of $4,582,000 for the nine months ended September 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 nine months ended September 30, 2002 with those of the prior year’s nine months.

	Nine Months Ended September 30					Increase			% Increase

	2002		2001			(Decrease)			(% Decrease)

Worldwide operations:

Operating revenue	$	3,696,000	$	2,522,000		$	1,174,000			47%
Gas volumes (Mcf)		2,684,000		1,780,000			904,000			51%
Oil volumes (Bbls)		11,000		9,700			1,300			13%
Average gas price per Mcf	$	1.25	$	1.27		$	(0.02	)		(2%	)
Average oil price per Bbl	$	19.11	$	26.88		$	(7.77	)		(29%	)
Operating expenses	$	2,108,000	$	1,618,000		$	490,000			30%
Average lifting cost per Mcf equivalent (“Mcfe”) sold	$	0.77	$	0.88		$	(0.11	)		(13%	)
General and administrative	$	3,692,000	$	3,073,000		$	619,000			20%
Depreciation, depletion and amortization (“DD&A”)	$	1,124,000	$	667,000		$	457,000			69%
DD&A rate per Mcfe volumes sold	$	0.41	$	0.36		$	0.05			14%
Interest expense	$	2,191,000	$	2,053,000		$	138,000			7%
Foreign currency exchange gain (loss)	$	19,000	$	(24,000	)	$	43,000			N/A

Australia operations:

Operating revenue	$	3,267,000	$	1,906,000		$	1,361,000			71%
Gas volumes (Mcf)		2,616,000		1,712,000			904,000			53%
Average gas price per Mcf	$	1.20	$	1.11		$	0.09			8%
Operating expenses	$	1,774,000	$	1,184,000		$	590,000			50%
Average lifting cost per Mcf sold	$	0.68	$	0.69		$	(0.01	)		(2%	)
Oil and Gas property DD&A	$	807,000	$	466,000		$	341,000			73%
Other DD&A	$	118,000	$	48,000		$	70,000			146%
Oil and Gas DD&A rate per Mcf volumes sold	$	0.31	$	0.27		$	0.04			13%

	Nine Months Ended September 30				Increase			% Increase

	2002		2001		(Decrease)			(% Decrease)


Domestic operations:

Operating revenue	$	429,000	$	616,000	$	(187,000	)		(30%	)
Gas volumes (Mcf)		68,000		68,000		—			0%
Oil volumes (Bbls)		11,000		9,700		1,300			13%
Average gas price per Mcf	$	3.11	$	5.22	$	(2.11	)		(40%	)
Average oil price per Bbl	$	19.11	$	26.88	$	(7.77	)		(29%	)
Operating expenses	$	334,000	$	434,000	$	(100,000	)		(23%	)
Average lifting cost per Mcfe sold	$	2.49	$	3.44	$	(0.95	)		(28%	)
Oil and Gas property DD&A	$	163,000	$	118,000	$	45,000			38%
Other DD&A	$	36,000	$	35,000	$	1,000			3%
Oil and Gas DD&A rate per Mcfe volumes sold	$	1.22	$	0.94	$	0.28			30%

Revenues and Volumes

Gas volumes sold in Australia increased 53% 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.

Gas volumes sold domestically remained flat at 68,000 Mcf. Higher gas production in early 2002 was offset by the loss of all domestic production following the sale of the Company’s West Buna field, in late May 2002. Oil volumes increased by 13% as higher oil production in early 2002 was partially offset by the loss of all domestic production due to the sale of the West Buna field. Domestic operating revenue decreased by 30% primarily due to declines in both oil and gas prices.

Costs and Expenses

Operating expenses in Australia increased 50% 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. In Australia, Oil and Gas property DD&A expense increased 73% primarily due to increasing sales volumes. Other DD&A expense increased for $70,000 in depreciation expense taken on the Company’s drilling rig.

Domestic operating expenses declined by 23% due to the Company’s reduced operating interest in the Hanna Basin project and the sale of the Company’s West Buna field, offset by costs associated with its new wells on the Lay Creek project. Domestic DD&A expense increased primarily due to an increase in the DD&A rate in 2002 caused by significant reserve reductions experienced with lower prices at December 31, 2001.

General and administrative expenses for the first nine months of 2002 increased 20% when compared to the nine months ended September 30, 2001 due primarily to increases in legal expense relating to the Tri-Star litigation and also to increases in compensation, consulting, insurance and travel expense, primarily related to taking over operations on the Comet Ridge project and expanding the Company’s consolidated interests in Comet Ridge.

Other Income (Expense)

Interest expense increased to $2,191,000 from $2,053,000 for the nine months ended September 30, 2002 compared to the three months ended September 30, 2001, due to higher interest rates and TCW financing cost amortization offset, by lower average principal balances over the nine months ended September 30, 2002.

The foreign exchange gain in the first nine months of 2002 and foreign exchange loss in the first nine months of 2001 resulted from 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 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.

Item. 3.

Quantitative and Qualitative Disclosures About Market Risk

Disclosure not required for small business issuers.

Item 4.

Controls and Procedures

Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, the Company conducted an evaluation of its disclosure controls and procedures, as such term is defined under Rule 13a-14(c) promulgated under the Securities Exchange Act of 1934, as amended within 90 days of the filing date of this report. Based on the evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective.

There have been no significant changes (including corrective actions with regard to significant deficiencies or material weaknesses) in the Company’s internal controls or in other factors that could significantly affect these controls subsequent to the date of the evaluation referenced above.

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

	10.88		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 September 1, 2002, filed herewith.

	10.89		Agreement by Tipperary Oil and Gas (Australia) to provide portion of funds to allow Mitchell Drilling Contractors Pty Ltd. (Mitchell) to purchase a new Soilmec Rig, enter into drilling contract with Mitchell and extend agreement for hire with Mitchell, dated October 7, 2002, filed herewith.

	99.4		Certification of Chief Executive Officer of Tipperary Corporation Pursuant to 18 U.S.C. §1350, filed herewith.

	99.5		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:

None

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: November 14, 2002	By:	/s/ DAVID L. BRADSHAW

		David L. Bradshaw, President, Chief Executive Officer and Chairman of the Board of Directors


Date: November 14, 2002	By:	/s/ JOSEPH B. FEITEN

		Joseph B. Feiten, Chief Financial Officer and Principal Accounting Officer

Certification of Chief Executive Officer
of Tipperary Corporation Pursuant to Section 302
of the Sarbanes-Oxley Act of 2002

I, David L. Bradshaw, certify that:

1. I have reviewed this quarterly report on Form 10-QSB of Tipperary Corporation;

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3 Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant, and we have:

a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.


Date: November 14, 2002			/s/ DAVID L. BRADSHAW

			President, Chief Executive Officer and Chairman of the Board

Certification of Chief Financial Officer of Tipperary Corporation Pursuant to Section 302
of the Sarbanes-Oxley Act of 2002

I, Joseph B. Feiten, certify that:

1. I have reviewed this quarterly report on Form 10-QSB of Tipperary Corporation;

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and


Date: November 14, 2002			/s/ JOSEPH B. FEITEN

			Chief Financial Officer and Principal Accounting Officer

Tipperary (TPY) Inactive 10QSB2002 Q3 Quarterly report (small business)

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