UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q/A

Amendment No. 1

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

For the quarterly period ended September 30, 2004

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 registrant as specified in its charter)

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

(303) 293-9379

(Issuer’s telephone number)

Indicate by check mark 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 ý    No o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Yes o    No ý

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 November 12, 2004
Common Stock, $.02 par value	41,333,994 shares

TIPPERARY CORPORATION AND SUBSIDIARIES

Index to Form 10-Q/A

EXPLANATORY NOTE
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Balance Sheets September 30, 2004 and December 31, 2003
	Consolidated Statements of Operations three and nine months ended September 30, 2004 and 2003
	Consolidated Statements of Stockholders’ Equity nine months ended September 30, 2004 and 2003
	Consolidated Statements of Cash Flows nine months ended September 30, 2004 and 2003
	Notes to Consolidated Financial Statements
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3.	Quantitative and Qualitative Disclosure About Market Risk
Item 4.	Controls and Procedures
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings
Item 2.	Changes in Securities
Item 6.	Exhibits and Reports on Form 8-K
SIGNATURES
EXHIBIT INDEX

EXPLANATORY NOTE

This Amendment No. 1 on Form 10-Q is being filed to amend Part I Item 4 of the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2004, filed on November 15, 2004 (the “Original 10-Q”).  This Amendment No. 1 does not otherwise alter the disclosures set forth in the Original 10-Q and does not reflect events occurring after the filing of the Original 10-Q.  This Amendment No. 1 is effective for all purposes as of the date of the filing of the Original 10-Q.

1

PART I - FINANCIAL INFORMATION

Item 1.    Financial Statements

TIPPERARY CORPORATION AND SUBSIDIARIES

Consolidated Balance Sheets

($in thousands except per share data)

(unaudited)

	September 30,			December 31,
	2004			2003
ASSETS
Current assets:
Cash and cash equivalents	$	8,590		$	2,996
Receivables	1,292			1,585
Other current assets	608			344
Total current assets	10,490			4,925
Property, plant and equipment, at cost:
Oil and gas properties, full cost method	127,654			120,703
Other property and equipment	4,517			4,431
	132,171			125,134
Less accumulated depreciation, depletion and amortization	(9,062		)	(8,078		)
Property, plant and equipment, net	123,109			117,056
Deferred loan costs	4,495			1,140
Other noncurrent assets	444			487
	$	138,538		$	123,608
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	4,000		$	—
Accounts payable	1,866			1,883
Accrued liabilities	1,308			2,329
Royalties payable	135			75
Total current liabilities	7,309			4,287
Long-term debt, net of current portion	90,834			74,126
Long-term asset retirement obligation	338			268
Commitments and contingencies (Note 6)
Minority interest	—			418
Stockholders’ equity
Preferred stock:
Cumulative; par value $1.00; 10,000,000 shares authorized; none issued	—			—
Non-cumulative, par value $1.00; 10,000,000 shares authorized; none issued	—			—
Common stock; par value $.02; 50,000,000 shares authorized; 41,343,594 and 39,231,087 shares issued, and 41,333,994 and 39,221,489 shares outstanding as of September 30, 2004 and December 31, 2003, respectively	827			785
Capital in excess of par value	158,310			149,970
Accumulated deficit	(124,583		)	(113,315		)
Accumulated other comprehensive income	5,528			7,094
Treasury stock, at cost; 9,598 shares	(25		)	(25		)
Total stockholders’ equity	40,057			44,509
	$	138,538		$	123,608

See accompanying notes to Consolidated Financial Statements.

2

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

	Three months ended						Nine months ended
	September 30,						September 30,
	2004			2003			2004			2003
Revenues	$	2,533		$	1,714		$	5,263		$	4,764
Costs and expenses:
Operating	1,483			1,257			4,124			3,320
Depreciation, depletion and amortization	539			455			1,146			1,161
Asset retirement obligation accretion	10			6			28			18
Impairment of oil and gas properties	—			165			150			2,386
General and administrative	2,081			1,353			5,635			4,165
Total costs and expenses	4,113			3,236			11,083			11,050
Operating loss	(1,580		)	(1,522		)	(5,820		)	(6,286		)
Other income (expense):
Interest and other income	42			13			149			30
Interest expense	(1,791		)	(1,403		)	(6,024		)	(3,883		)
Write-off of deferred loan costs	—			(5,069		)	—			(5,069		)
Foreign currency exchange gain (loss)	18			(1,053		)	9			2,060
Total other income (expense)	(1,731		)	(7,512		)	(5,866		)	(6,862		)
Loss before income taxes	(3,311		)	(9,034		)	(11,686		)	(13,148		)
Income tax benefit	—			—			—			—
Loss before minority interest and cumulative effect of accounting change	(3,311		)	(9,034		)	(11,686		)	(13,148		)
Minority interest in loss (income) of subsidiary	—			230			418			49
Loss before cumulative effect of accounting change	(3,311		)	(8,804		)	(11,268		)	(13,099		)
Cumulative effect of accounting change	—			—			—			(46		)
Net loss	$	(3,311	)	$	(8,804	)	$	(11,268	)	$	(13,145	)
Net loss per share basic and diluted	$	(.08	)	$	(.22	)	$	(.29	)	$	(.34	)
Weighted average shares outstanding basic and diluted	39,553			39,221			39,390			39,221

See accompanying notes to Consolidated Financial Statements.

3

TIPPERARY CORPORATION AND SUBSIDIARIES

Consolidated Statements of Stockholders’ Equity (Unaudited)

For the Nine Months Ended September 30, 2003 and 2004

(in thousands)

	Common Stock			Capital in excess of		Accumulated			Accumulated Other Comprehensive			Treasury Stock
	Shares	Amount		par value		Deficit			Income			Shares	Amount			Total
Balance at December 31, 2002	39,221	$	785	$	149,953	$	(97,946	)	—			10	$	(25	)	$	52,767
Net loss	—	—		—		(13,145		)	—			—	—			(13,145		)
Other comprehensive income:
Foreign currency translation adjustment	—	—		—		—			3,663			—	—			3,663
Comprehensive loss																(9,482		)
Compensatory warrants granted for services	—	—		17		—			—			—	—			17
Balance at September 30, 2003	39,221	$	785	$	149,970	$	(111,091	)	$	3,663		10	$	(25	)	$	43,302
Balance at December 31, 2003	39,221	$	785	$	149,970	$	(113,315	)	$	7,094		10	$	(25	)	$	44,509
Net loss	—	—		—		(11,268		)	—			—	—			(11,268		)
Other comprehensive loss:
Foreign currency translation adjustment	—	—		—		—			(1,566		)	—	—			(1,566		)
Comprehensive loss																(12,834		)
Issuance of common stock for cash	2,000	40		7,960		—			—			—	—			8,000
Compensatory warrants granted for services	—	—		81		—			—			—	—			81
Stock options exercised	113	2		299		—			—			—	—			301
Balance at September 30, 2004	41,334	$	827	$	158,310	$	(124,583	)	$	5,528		10	$	(25	)	$	40,057

See accompanying notes to Consolidated Financial Statements.

4

TIPPERARY CORPORATION AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(in thousands)

(unaudited)

	Nine months ended
	September 30,
	2004			2003
Cash flows from operating activities:
Net loss	$	(11,268	)	$	(13,145	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization	1,146			1,161
Amortization of deferred loan costs	418			5,770
Compensatory warrants granted	81			6
Minority interest in loss of subsidiary	(418		)	(49		)
Asset retirement obligation accretion	28			18
Cumulative effect of accounting change	—			46
Impairment of oil and gas properties	150			2,386
Foreign currency exchange gain	—			(2,070		)
Changes in current assets and current liabilities:
Decrease (increase) in receivables	293			(178		)
Increase in other current assets	(264		)	(395		)
(Decrease) increase in accounts payable and accrued liabilities	(153		)	823
Increase (decrease) in royalties payable	60			(41		)
Net cash used in operating activities	(9,927		)	(5,668		)
Cash flows from investing activities:
Proceeds from asset sales	—			2,912
Capital expenditures	(12,858		)	(26,340		)
Net cash used in investing activities	(12,858		)	(23,428		)
Cash flows from financing activities:
Proceeds from issuance of common stock and exercise of stock options	8,301			—
Proceeds from borrowings	94,309			55,512
Principal repayments	(70,382		)	(27,129		)
Decrease in restricted cash	—			546
Payments for deferred loan costs	(3,790		)	(362		)
Net cash provided by financing activities	28,438			28,567
Effect of exchange rate changes on cash	(59		)	(130		)
Net increase (decrease) in cash and cash equivalents	5,594			(659		)
Cash and cash equivalents at beginning of period	2,996			1,725
Cash and cash equivalents at end of period	$	8,590		$	1,066

See accompanying notes to Consolidated Financial Statements.

5

TIPPERARY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 - OPERATIONS AND 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, 2004, and the results of their operations for the three-month and nine-month periods ended September 30, 2004 and 2003 and their cash flows for the nine-month periods ended September 30, 2004 and 2003. The Consolidated Financial Statements include the accounts of Tipperary Corporation and its wholly-owned subsidiaries, Tipperary Oil and Gas Corporation, Tipperary CSG Inc., 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-K for the year ended December 31, 2003. These financial statements should be read in conjunction with the Form 10-K.

New Accounting Pronouncements

The Company follows the full cost method to account for its oil and gas exploration and development activities as more fully described in the Company’s Annual Report on Form 10-K for the year ended December 31,2003. SEC Staff Accounting Bulletin 106 (September 2004) requires estimated future asset retirement obligations to be included in the amortization base, whereby such costs are amortized over proved reserves. Such obligations are to be excluded in the determination of the ceiling for capitalized costs. Compliance with the bulletin, effective in the fourth quarter of 2004, is not expected to have a significant effect on the ceiling calculation or depreciation, depletion and amortization expense.

The Company has reviewed all other recently issued, but not yet adopted, accounting pronouncements and standards to determine their effects, if any, on its results of operations or financial position. Based on its review, the Company believes that none of these pronouncements will have a significant effect on its current or future financial position or results of operations.

Asset Retirement Obligation

On January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”), 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 No. 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 Company has determined that it has asset retirement costs associated with wells drilled in Australia and the United States. The Company also expects to incur retirement costs to dismantle two gas compression plant facilities located in Australia. The following table sets forth the changes in the asset retirement obligation:

(in thousands)
Beginning asset retirement obligation at December 31, 2003	$	268
Asset retirement obligation accretion	28
Asset retirement obligation additions	42
Payments on asset retirement obligation	—
Ending asset retirement obligation at September 30, 2004	$	338

6

Stock-Based Compensation

SFAS Nos. 148 and No. 123 encourage, but do not require, companies to record the compensation cost for stock-based employee compensation plans at fair value. At September 30, 2004, the Company had two stock-based employee option plans and warrants issued to directors and employees. The Company has chosen to continue to account for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” (“APB 25”) and has applied the disclosure provisions of SFAS Nos. 123 and 148. Accordingly, compensation cost for fixed stock options and warrants is measured as the excess, if any, of the quoted market price of the Company’s stock at the date of the grant over the amount an employee must pay to acquire the stock. Pro forma disclosures as if the Company had adopted the cost recognition provisions of SFAS Nos. 148 and 123 are presented below:

	Nine Months Ended September 30,
	2004			2003
	(in thousands, except per share data)
Net loss, as reported	$	(11,268	)	$	(13,145	)
Add:
Total compensation cost included in reported net loss, net of $0 tax	—			—
Deduct:
Total compensation cost determined under fair value based method for all awards, net of $0 tax	(43		)	(110		)
Pro forma net loss	$	(11,311	)	$	(13,255	)
Loss per share
Basic and diluted—as reported	$	(. 29	)	$	(.34	)
Basic and diluted—pro forma	$	(. 29	)	$	(.34	)

	Three Months Ended September 30,
	2004			2003
	(in thousands, except per share data)
Net loss, as reported	$	(3,311	)	$	(8,804	)
Add:
Total compensation cost included in reported net loss, net of $0 tax	—			—
Deduct:
Total compensation cost determined under fair value based method for all awards, net of $0 tax	(14		)	(37		)
Pro forma net loss	$	(3,325	)	$	(8,841	)
Loss per share
Basic and diluted—as reported	$	(. 08	)	$	(.22	)
Basic and diluted—pro forma	$	(. 08	)	$	(.23	)

7

Revenue Recognition and Gas Imbalances

The Company recognizes natural gas and oil revenue from its interests in producing wells as natural gas and oil are produced and sold from those wells. The Company uses the sales method of accounting for these revenues. Under the sales method, revenues are recognized based on actual volumes sold to purchasers. With natural gas production operations, joint owners may take more or less than the production volumes entitled to them under the governing operating agreement. 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, 2004, the Company had taken and sold more than its entitled share of natural gas volumes produced from the Comet Ridge project, and was overproduced by approximately 1,821 MMcf (net of royalties). Based on the September 30, 2004 average sales price of $1.70 per Mcf, this overproduction represents approximately $3.1 million in gas revenues. No liability has been recorded for the excess volumes taken, as they do not exceed the Company’s share of remaining proved reserves. Under the terms of the governing gas balancing agreement, the Company may be required to reduce the monthly volumes it sells by up to 50% of its entitled share of sales, to enable underproduced parties to sell more than their entitled share of the gas sales and cure the imbalance.

Foreign Currency

The functional currency of the Company’s Australian subsidiary, TOGA, is the Australian dollar. As the functional currency is the local currency, the current rate method is used to translate Australian dollar financial statements into U.S. dollars for TOGA. All assets and liabilities are translated using current exchange rates, while revenues and expenses are translated at rates in existence when the transactions occurred. The translation adjustment that results from using varying rates in the translation process is reported as a component of other comprehensive income (loss) and is accumulated and reported as a separate component of stockholders’ equity in the Company’s Consolidated Financial Statements.

The cumulative foreign currency translation adjustment (net of $0 tax) as of September 30, 2004 and December 31, 2003 totaled $5.5 million and $7.1 million, respectively, of other comprehensive income.

Liquidity and Operations

The Company had cash and cash equivalents of $8.6 million as of September 30, 2004, compared to approximately $3.0 million as of December 31, 2003. In September 2004, the Company sold two million shares of its common stock in a private placement to 11 unaffiliated institutional investors for $4.00 per share.

The Company anticipates funding operations and capital expenditures in Australia for the remainder of 2004 using funds from a $150 million AUD (approximately $114 million USD) financing facility (see Note 3).

On October 30, 2004, the Company and Tri-Star entered into a settlement agreement covering the litigation between the two parties. Subject to certain events occurring within 45 days of the settlement agreement, the Company will pay $5 million to Tri-Star, and the Company will receive from Tri-Star approximately 96% of the registered titles for the Comet Ridge project and 2.25% working interest in the Comet Ridge project, subject to a 1.5% contractual overriding royalty interest to be retained by Tri-Star. See Note 6. The Company expects to fund this contingent commitment with funds from its available cash and with funds from TOGA’s Australian loan facility.

The Company anticipates funding operations and capital expenditures in the United States for the remainder of 2004 using (a) cash on hand at September 30, 2004 and (b) a commitment from Slough Estates USA Inc. (“Slough”), the Company’s majority shareholder, to provide funds for working capital, board-approved capital expenditures and operations through April 2005.

Property, Plant and Equipment

With regards to the aforementioned settlement agreement, the Company’s current assessment is that the fair market value of the registered titles collectively is at least the sum of (a) the $5 million the Company would pay Tri-Star and (b) the fair market value of the overriding royalty interest payable to Tri-Star, less (c) the fair market value of the working interest being received from Tri-Star, whereby the $5 million will be recorded as an addition to the Company’s Australian

8

full cost pool as the cost of acquiring the titles and working interest, subject to the overriding royalty.

NOTE 2 - RELATED PARTY TRANSACTIONS

At September 30, 2004, the Company owed Slough and Slough Trading Estates Limited (“STEL”), a United Kingdom company which is the parent of Slough, approximately $17.0 million.

As of September 30, 2004, the Company had one credit facility agreement with STEL allowing the Company to borrow on an unsecured basis up to $13.0 million for its U.S. operations. Using borrowings from this credit facility, the Company substantially funded its operating and capital needs in the United States during 2003 and through the first nine months of 2004. The Company may repay the loan in whole or in part without prepayment penalties. The credit facility bears interest at 13% per annum and is due April 2, 2012. STEL may demand repayment prior to the maturity date provided that STEL gives 18-months notice. So long as the STEL indebtedness exists, the Company may not obtain any additional third party indebtedness, either secured or unsecured, or making a priority payment in respect of any obligation without first obtaining written approval from STEL. In connection with this credit facility, the Company paid STEL arrangement fees of $40,000. The U.S. dollar value of the outstanding balance of this facility as of September 30, 2004 was $13.0 million.

In 2002, the Company borrowed $4 million from Slough which is evidenced by a note payable that bears interest at LIBOR plus 3.5% (5.30% as of September 30, 2004) and is payable in full on April 30, 2005.

Slough Estates plc, STEL’s parent, has guaranteed for a period up to five years through June 2009 a bank credit facility of $150.0 million AUD that closed in June 2004 (See Note 3). As consideration for the guarantee, the Company pays 1% per annum on the daily outstanding balance of the debt guaranteed. For the nine month period ended September 30, 2004, the Company had paid guarantee fees of $211,000.

In August 2003, TOGA borrowed $29.7 million ($45 million AUD) from STEL for the sole purpose of paying off a $22 million long-term debt owed TCW Asset Management Company (“TCW”) and to substantially fund a $7.7 million repurchase of the 6% overriding royalty held by TCW on the Company’s Comet Ridge properties. In addition, TOGA borrowed $55.0 million AUD under a credit facility agreement with STEL to fund its operations in Australia. These loans bore interest at 13% per annum. In connection with these loans, the Company paid arrangement fees of $250,000 USD and $100,000 AUD, respectively, to STEL. These loans were paid in full June 18, 2004 with funds from a bank credit facility (see Note 3).

For the nine month period ended September 30, 2004 and 2003, approximately $5.9 million and $2.0 million, respectively, in interest and fees were paid collectively to Slough and STEL under the financing agreements discussed herein.

NOTE 3 - BANK DEBT

On June 9, 2004, TOGA entered into a $150.0 million AUD senior credit facility agreement with Australia and New Zealand Banking Group Limited and BOS International (Australia) Limited for the purpose of paying in full TOGA’s borrowings of $100.0 million AUD from STEL (see Note 2) and to fund TOGA’s operating costs and its share of development costs of the Comet Ridge coalseam gas project in Queensland, Australia. Funds from the facility are expected to be available over five years and repayable in variable amounts beginning in 2007 and concluding in 2014. The interest rate for the facility (6.425% per annum as of September 30, 2004) varies with the Australian inter-bank rate plus other factors. Commitment fees of 0.425% per annum of committed but undrawn funds, as defined in the credit facility, are payable semi-annually. The facility’s effective interest rate at September 30, 2004, including interest, commitment and guarantee fees, and amortization of loan costs, is 8.725%. The facility is collateralized by, among other things, TOGA’s common stock and the Company’s consolidated interest in the Comet Ridge project and is guaranteed for up to five years by Slough Estates plc (See Note 2). The facility contains certain restrictive covenants, including maintenance of certain financial ratios and contains provisions that allow the Company to utilize the facility to finance facility interest expense. The U.S. dollar value of the outstanding balance of this facility and facility interest expense payable as of September 30, 2004 was approximately $77.8 million ($108.9 million AUD). TOGA incurred $4.5 million in loan costs which the Company has deferred and is amortizing over five years.

9

NOTE 4 - LOSS PER SHARE

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

	Three Months Ended September 30,
	2004			2003
Numerator:
Net loss	$	(3,311	)	$	(8,804	)
Denominator:
Weighted-average shares outstanding	39,553			39,221
Effect of dilutive securities:
Assumed exercise of dilutive options and warrants	—			—
Weighted-average shares and dilutive potential common shares	39,553			39,221
Basic and diluted loss per share	$	(.08	)	$	(.22	)
Total options and warrants which could potentially dilute basic EPS in future periods	3,511			3,573

	Nine Months Ended September 30,
	2004			2003
Numerator:
Net loss	$	(11,268	)	$	(13,145	)
Denominator:
Weighted-average shares outstanding	39,390			39,221
Effect of dilutive securities:
Assumed exercise of dilutive options and warrants	—			—
Weighted-average shares and dilutive potential common shares	39,390			39,221
Basic and diluted loss per share	$	(.29	)	$	(.34	)
Total options and warrants which could potentially dilute basic EPS in future periods	3,511			3,573

NOTE 5 - MINORITY INTEREST IN TOGA

For the nine month period ended September 30, 2004, the 10% minority interest share of TOGA’s net loss totaled $866,000. The minority interest in TOGA’s net equity at January 1, 2004 totaled $418,000, resulting in the Company recognizing an additional loss of $468,000. The Company will continue recognizing 100% of TOGA’s net losses until TOGA becomes profitable. The Company will record 100% of TOGA’s net income until it has recouped the minority interest’s share of TOGA’s net losses.

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NOTE 6 - 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 has answered the allegations, and filed amended pleadings denying liability and raising a number of affirmative defenses and asserting various counterclaims. TOGA has operated the project since March 2002, after 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.

On October 30, 2004, the Company and Tri-Star entered into a settlement agreement covering this litigation, as well as all other litigation between those parties originating in Queensland, Australia. Among other provisions, the settlement agreement provides that, upon receipt of necessary governmental consents and/or approvals in Queensland, Australia, Tri-Star will transfer to a newly-formed subsidiary of the Company, Tipperary Queensland, Inc., a 2.25% working interest in the Comet Ridge project, subject to a 1.5% contractual overriding royalty interest to be retained by Tri-Star out of the conveyed interest. Tri-Star will also transfer to the Company approximately 96% of each of the registered titles for the Comet Ridge project, including, but not limited to, the relevant Authorities to Prospect and Petroleum Leases. The remaining percentage of the registered titles will be conveyed to two unrelated intervening plaintiffs owning a present interest in the Comet Ridge project, representing their proportionate share of the Project. Upon receipt of the necessary consents and approvals in Queensland and the transfer of the interest subject to the overriding royalty interest, the Company will pay (U.S.) $5 million to Tri-Star and Tri-Star will acknowledge the Company’s right to be operator of the Comet Ridge project. The Company anticipates using TOGA’s Australian loan facility and existing Tipperary cash to fund the $5 million payment to Tri-Star. Should all necessary governmental consents and approvals be obtained within 45 days of the date of the settlement agreement, the Company and Tri-Star will dismiss all claims against the other in the action in Midland County, Texas with no ability to refile, seek the dismissal of all action pending in Queensland, Australia, and each party will release the other from all liability. If the necessary governmental consents, approvals or conditions in Queensland are denied, not received or otherwise not met within 45 days from the date of the settlement agreement, either party can avoid the settlement agreement and consider the settlement at an end. The District Court in Midland County, Texas has granted a continuance of the action for a period of time sufficient to allow the parties to attempt to obtain the requisite approvals and consents, and fulfill any other conditions, in Queensland, Australia. Should the settlement agreement come to an end, the case will be reassigned to the trial docket in Midland County, Texas.

11

NOTE 7 - OPERATIONS BY GEOGRAPHIC AREA

Segment information has been prepared in accordance with SFAS No. 131, “Disclosures About Segments of an Enterprise and Related Information.” The Company has two geographic reporting segments, Australia and the United States. General and administrative expenses, interest expense and interest and other income are not allocated to segments. The segment data presented below was prepared on the same basis as the Consolidated Financial Statements. Reportable business segment information as of September 30, 2004 and 2003 and for the three and nine months ended September 30, 2004 and 2003 is as follows (in thousands):

As of and for the three months ended September 30, 2004

	Gas and Oil Operations
	Australia		United States			Total		Non-Segmented Items			Total
Revenues	$	2,531	$	2		$	2,533	$	—		$	2,533
Income (loss) before minority interest and income taxes	773		(258		)	515		(3,826		)(1)	(3,311		)
Property, plant and equipment, net	112,838		9,873			122,711		398			123,109

(1) Includes $975,000 of legal expenses for the Tri-Star trial (see Note 6) and $1.1 million of other general and administrative expenses, and $1.8 million of interest expense.

As of and for the three months ended September 30, 2003

	Gas and Oil Operations
	Australia		United States			Total			Non-Segmented Items			Total
Revenues	$	1,710	$	4		$	1,714		$	—		$	1,714
Income (loss) before minority interest and income taxes	287		(443		)	(156		)	(8,878		)(1)	(9,034		)
Property, plant and equipment, net	96,637		6,139			102,776			390			103,166

(1) Includes $1.4 million of general and administrative expenses, $1.4 million of interest expense, $5.1 million of write-off of deferred loan costs and $1.1 million of foreign currency exchange loss.

As of and for the nine months ended September 30, 2004

	Gas and Oil Operations
	Australia		United States			Total			Non-Segmented Items			Total
Revenues	$	5,256	$	7		$	5,263		$	—		$	5,263
Income (loss) before minority interest and income taxes	746		(889		)	(143		)	(11,543		)(1)	(11,686		)
Property, plant and equipment, net	112,838		9,873			122,711			398			123,109

(1) Includes $1.9 million of legal expenses for the Tri-Star trial (see Note 6) and $3.7 million of other general and administrative expenses and $6.0 million of interest expense.

12

As of and for the nine months ended September 30, 2003

	Gas and Oil Operations
	Australia		United States			Total			Non-Segmented Items			Total
Revenues	$	4,753	$	11		$	4,764		$	—		$	4,764
Income (loss) before minority interest and income taxes	963		(3,046		)	(2,083		)	(11,065		)(1)	(13,148		)
Property, plant and equipment, net	96,637		6,139			102,776			390			103,166

(1) Includes $4.2 million of general and administrative expenses, $3.9 million of interest expense, $5.1 million of write-off of deferred loan costs and $2.1 million of foreign currency exchange gain.

NOTE 8 - PROPERTY, PLANT AND EQUIPMENT

A summary of property, plant and equipment follows:

	September 30, 2004			December 31, 2003
	(in thousands)
Evaluated oil and gas properties:
Australian properties	$	105,451		$	105,264
Domestic properties	—			—
Unevaluated oil and gas properties:
Australian properties	12,330			9,221
Domestic properties	9,874			6,218
Oil and gas properties	127,655			120,703
Other property and equipment	4,516			4,431
	132,171			125,134
Less accumulated depreciation, depletion and amortization	(9,062		)	(8,078		)
Property, plant and equipment, net	$	123,109		$	117,056

NOTE 9 - STATEMENT OF CASH FLOWS SUPPLEMENTAL INFORMATION

	Nine Months Ended September 30,
	2004		2003
	(in thousands)
Cash paid during the period for interest, net of amounts capitalized	$	4,734	$	2,860
Non-cash investing and financing activities—
Net increase in payables for capital expenditures	$	885	$		—

13

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-K for the year ended December 31, 2003, for meaningful cautionary language and discussion of risk factors disclosing why actual results may vary materially from those anticipated by management.

Overview

Australia

The Company’s activities in Australia are conducted substantially through Tipperary Corporation’s 90%-owned Australian subsidiary, Tipperary Oil & Gas (Australia) Pty Ltd (“TOGA”). As of September 30, 2004, the Company owned a 73% undivided capital-bearing interest in the Comet Ridge project in Queensland, Australia. This project comprises approximately 1,230,500 acres in the Bowen Basin, which includes five petroleum leases covering approximately 288,000 acres, Authority to Prospect (“ATP”) 526 covering approximately 712,000 acres, ATP 653 covering approximately 96,000 acres and ATP 745 covering approximately 135,000 acres. The Company also holds 100% of ATP 655, which is near the Comet Ridge project and covers approximately 77,000 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 as determined by Queensland’s Department of Natural Resources and Mines (“Queensland DNRM”) 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.

With respect to ATP 653, the Company filed and received a variance to combine year two expenditure requirements with those of year three and to drill a horizontal well eliminating the obligation to drill two conventional wells. Drilling of the horizontal well is expected to commence in late 2004 or early 2005. The Company has completed expenditure requirements for ATPs 745 and 655.

Upon expiration of an ATP, the policy of the Queensland DNRM allows the ATP holder to renew the ATP for an additional four year exploratory period and generally requires the holder to relinquish a 20% portion of ATP acreage not held by a petroleum lease.  ATP 526 expired on October 31, 2004, and an application has been filed with the Queensland DNRM for the renewal of ATP 526.  With regards to renewal, there will be discussion with the Queensland DNRM of establishing petroleum leases on acreage that is part of ATP 526 and ATP 653.  ATPs 653, 655 and 745 have initial terms expiring on September 30, 2006, October 31, 2007 and October 31, 2007, respectively.

The Company’s gas marketing in eastern Australia is currently focused on obtaining long-term gas sales agreements that provide five to 15 years of firm sales typically starting in 2006 to 2008. Short-term sales contracts are also being pursued. Effective July 2004, the Company commenced selling gas under two short-term sales contracts, one for six months and one for 12 months.

14

The following table summarizes field development progress on the Comet Ridge project as of September 30, 2004. In December 2003, the Company began using its second compression plant facility, which increased the field’s gas compression capacity to approximately 38 million cubic feet (“MMcf”) per day.

Comet Ridge Operations Review

	September 30, 2004 (a)
Well Status (Number of Wells)
Selling	46
Dewatering or temporarily shut-in	30
Producing	76
Being evaluated	21
Injection/monitoring wells	2
To be plugged and abandoned	2
Plugged and abandoned	3
Total drilled	104
Gross Daily Volumes (MMcf)
Sold	29
Flared	1
Used for compression fuel	3
Produced	33

(a)   This table shows the status of wells drilled at September 30, 2004 and gross daily volumes on that same date. Average gross daily volumes for the quarter may differ. Net sales volumes are discussed in the Company’s results of operations.

The Company drilled two exploratory wells on the Comet Ridge project during the first nine months of 2004. The 2004 drilling was substantially funded with borrowings from Slough Trading Estates Limited (“STEL”) and an Australian bank senior credit facility described in Note 3 to the Consolidated Financial Statements. Future 2004 development and exploratory costs will be funded by the Australian bank senior credit facility.

During the first half of 2004, 100% of the Company’s gas sales in Australia were made under a five-year contract effective June 1, 2000 with ENERGEX Retail Pty Ltd (“Energex”), an unaffiliated customer. The Energex contract has delivery requirements of up to approximately 15,000 Mcf of gas per day. The Company has a gas sales agreement with Origin Energy Retail Limited (“OERL”), a subsidiary of Origin Energy Limited, to supply approximately 9 Bcf per year, or approximately 25,000 Mcf of gas per day net to the Company’s interests, for 13 years beginning May 2007. Origin Energy Limited is a large Australian integrated energy company which, through subsidiaries, owns nearly 24% of the Comet Ridge project.

15

During the third quarter of 2004, the Company sold its gas under three contracts, the Energex contract discussed above and two new short-term contracts that commenced in July 2004 - one six month contract with Energex and one 12 month contract with Santos QNT Pty Ltd. With the new short-term contracts and increased demand, the Company’s sales increased to 1,505 MMcf for the third quarter in 2004, a 60% increase over the second quarter’s sales of 938 MMcf and a 31% increase over the prior year’s quarter.

Effective September 30, 2004, the Company and Queensland Fertilizer Assets Limited (“QFAL”) extended until December 31, 2004 the Company’s gas sales agreement with QFAL to supply 210 Bcf of gas to QFAL over a 20-year period beginning in early 2007 to a fertilizer plant QFAL is proposing to construct in southeastern Queensland. The Company does not yet know if the plant will be built and may in 2005 discontinue the agreement.

United States

Lay Creek — The Company holds a 50% working interest in Lay Creek, a coalseam gas project located in Moffat County, Colorado. The project includes various leasehold interests covering over 82,000 gross acres. Koch Exploration Company (“Koch”), an unaffiliated third party, holds the remaining 50% working interest and operates the project. The Company is currently evaluating the gas and water production from pilot wells in order to determine economic viability of the production. Gas production in excess of 300 Mcf per day from nine wells is currently being flared. The Company is investigating pipeline connections and expects to begin selling gas in 2005.

Frenchman — The Company holds a 25% interest in the Frenchman prospect in eastern Colorado. Total gross acreage in the prospect is approximately 162,000 acres. The Houston Exploration Company (“Houston Exploration”) holds the remaining 75% interest and is the operator of the prospect. Houston Exploration recently acquired this interest from Kerr-McGee Rocky Mountain Corporation (“Kerr-McGee”). During 2003, five wells were drilled on the Frenchman prospect by Kerr-McGee. Three of these wells were completed, and two were plugged and abandoned. In 2004, the Company drilled five additional Frenchman wells in which the former operator, Kerr-McGee, elected not to participate. The Company has a 100% interest in these wells. The Company believes four of these 100% wells will be commercial producers, and the Company will earn 100% of offsetting drill sites as set forth in the operating agreement the Company had with Kerr-McGee. The Company plugged and abandoned the other well drilled. In the first quarter of 2004, the Company recorded an asset impairment expense of $150,000 related to unsuccessful exploration costs incurred on wells on the Frenchman prospect. Two more wells are expected to be drilled by the Company on 100% owned acreage in the fourth quarter of 2004 at a cost to the Company of approximately $420,000. Further seismic work is expected to be conducted during the fourth quarter of 2004. The Company expects to build a gathering system at a cost of approximately $200,000 to the Company, connect to a nearby pipeline and begin selling gas in early in 2005.

Republican — The Company holds a 20% interest in the Republican prospect in eastern Colorado. Total gross acreage in the prospect is approximately 170,000 acres. Houston Exploration, which acquired Kerr-McGee’s interest in the project, holds the remaining 80% interest and is the operator of the prospect. Five wells were drilled on the Republican prospect in 2004 by Kerr-McGee, and the economics of connecting these wells to nearby pipelines are being evaluated. Houston Exploration and the Company are currently evaluating additional drilling locations to be drilled during the fourth quarter of 2004, and expect to begin a large 3-D seismic acquisition program in 2005.

Stateline — The Company holds a 25% interest in the Stateline prospect in western Nebraska. Total gross acreage in the prospect is approximately 120,000 acres. Lance Oil & Gas Company, Inc. (“Lance”) holds the remaining 75% interest and is the operator of the prospect. In the first half of 2004, preliminary 2-D seismic operations were conducted at a cost to the Company of approximately $100,000. The acquisition of 3D seismic data is now planned for early 2005 at a cost to the Company of approximately $163,500.

Sand Hill — During late 2003, the Company acquired leasehold acreage in western Nebraska totaling approximately 51,000 gross acres, the “Sand Hill” prospect. This acreage is located in the vicinity of the Company’s Frenchman, Republican and Stateline prospects. The Company may sell an interest in the prospect to recover its investment and retain an interest in this acreage. Alternatively, the Company may elect to explore and develop this prospect independently. The Company intends to commence a seismic program in the fourth quarter of 2004 at an estimated cost of $600,000.

16

Nine Mile — The Company holds a 70% interest in the prospective acreage and 40% interest in the outlying acreage of the Nine Mile prospect, a conventional oil and gas exploration prospect, also located in Moffat County, Colorado, and serves as operator of the prospect. The prospect comprises approximately 38,000 gross acres. The Company is currently evaluating exploratory work performed in 2002 and 2003 and is seeking industry partners before resuming exploratory activity.

Financial Condition, Liquidity and Capital Resources

The Company had cash and cash equivalents of $8.6 million as of September 30, 2004, compared to approximately $3.0 million as of December 31, 2003. In September 2004, the Company sold two million shares of its common stock in a private placement to 11 unaffiliated institutional investors for $4.00 per share. The Company has funded operations, deferred loan costs associated with obtaining TOGA’s senior credit facility and capital expenditures for the nine months ended September 30, 2004, using primarily (a) cash on hand at December 31, 2003 and (b) borrowings from STEL and from TOGA’s senior credit facilities.

On October 30, 2004, the Company and Tri-Star entered into a settlement agreement covering the litigation between the two parties. Subject to certain events occurring within 45 days of the settlement agreement, the Company will pay $5 million to Tri-Star, and the Company will receive from Tri-Star approximately 96% of the registered titles for the Comet Ridge project and a 2.25% working interest in the Comet Ridge project, subject to a 1.5% contractual overriding royalty interest to be retained by Tri-Star.  See Note 6. The Company expects to fund this contingent commitment with funds from its available cash and with funds from TOGA’s Australian loan facility.

Shortly after the settlement agreement was reached, Slough Estates plc, parent of Slough and STEL, publicly announced that it will consider its options for exiting from its investment in Tipperary.  The Company will be conducting discussions with Slough relating to this announcement.  TOGA’s $150 million AUD bank facility entered into on June 9, 2004, provides that Slough Estates plc, as parent of Tipperary’s majority shareholder and as recourse guarantor of the bank facility, cannot divest of controlling interest of Tipperary during the ten-year term of the loan without approval by the facility’s lenders, acting reasonably.  In addition, STEL’s lending agreement with Tipperary requires STEL to give Tipperary 18 months notice for repayment of the amounts borrowed by Tipperary.  At September 30, 2004, the outstanding borrowings on the Australian Bank Facility were $108.9 million AUD, and the outstanding borrowings on the STEL lending agreement were $13.0 million USD.

The Company anticipates funding operations and capital expenditures in Australia for the remainder of 2004 using funds from a $150 million AUD (approximately $114 million USD) credit facility. See Note 3 to the Consolidated Financial Statements.

The Company anticipates funding operations and capital expenditures in the United States for 2004 using (a) cash on hand at September 30, 2004 and (b) a commitment from Slough to provide funds for working capital, board-approved capital expenditures and operations through April 2005.

Net cash used by operating activities was $10.6 million during the nine months ended September 30, 2004, compared to $5.7 million of cash used during the same period last year. The increase in net cash used for operations in the first nine months of 2004 compared with the same period in 2003 resulted primarily from (a) interest expense on increased debt used to fund property acquisition, exploration and development and (b) higher operating costs and general and administrative expenses.

On June 9, 2004, TOGA entered into a $150.0 million AUD senior credit facility agreement with Australia and New Zealand Banking Group Limited and BOS International (Australia) Limited. The initial borrowings under the facility totaled $103.0 million AUD ($71.0 million USD). TOGA used $100.0 million AUD ($68.2 million USD) to pay in full its borrowings from STEL and to pay debt issuance costs. The balance of the credit facility will be used to fund TOGA’s operating costs and its share of development costs of the Comet Ridge coalseam gas project in Queensland, Australia.

17

The table below provides an analysis of capital expenditures of $12.9 million during the nine months ended September 30, 2004.

Capital Expenditures Activity

(in thousands)

Australia:
Comet Ridge drilling and completion	$		7,169
Comet Ridge facilities and equipment	126
ATP 655 exploration	782
Capitalized interest	817
Other	186
Domestic:
Leasehold acquisitions	967
Capitalized interest	388
Lay Creek drilling and completion	1,636
Frenchman drilling and completion	670
Other	117
Total	$	12,858

Capital expenditures for the first nine months of 2004 were funded principally under credit facilities with STEL and the Australian bank senior credit facility.

The Company has various commitments in addition to its long-term debt. The table below summarizes the Company’s contractual obligations for the last three months of 2004 and years 2005 through 2007 and thereafter (in thousands):

Contractual Obligation	Total		2004		2005		2006		2007		Thereafter
Long-term debt	$	90,834	$	—	$	—	$	—	$	2,100	$	88,734
Operating leases for office space	$	999	$	80	$	319	$	324	$	265	$	11
Operating leases for equipment	$	282	$	44	$	162	$	44	$	32	$	—
Standby drilling fees	$	60	$	—	$	60	$	—	$	—	$	—
Petroleum lease expenditures	$	1,100	$	—	$	550	$	275	$	275	$	—
Asset retirement obligation	$	5,034	$	—	$	—	$	—	$	—	$	5,034

18

Results of Operations - Comparison of the Three Months Ended September 30, 2004 and 2003

Unless otherwise indicated, the discussion below compares the quarter ended September 30, 2004 to the quarter ended September 30, 2003. The Company incurred a net loss of $3.3 million compared to a net loss of $8.8 million. An increase in revenues for 2004 was offset by higher legal expenses related to Tri-Star litigation included within general and administrative costs . The greater net loss for the 2003 quarter was primarily due to (a) a $5.1 million write-off of deferred loan costs and (b) a $1.1 million foreign currency exchange loss. The table below provides a comparison of operations, respectively. It is intended to provide a comparative review of significant operational items. Accordingly, nominal differences may exist from the amounts presented in the accompanying Consolidated Financial Statements.

	Three Months Ended September 30,				Increase			% Increase
	2004		2003		(Decrease)			(Decrease)
	($ in thousands, except average per Mcf prices and costs)
Worldwide operations:
Operating revenue	$	2,533	$	1,714	$	819		48	%
Gas volumes (MMcf)	1,506		1,149		357			31	%
Average gas price per Mcf	$	1.68	$	1.49	$	0.19		13	%
Operating expenses	$	1,483	$	1,256	$	227		18	%
Average lifting cost per Mcf equivalent (“Mcfe”) sold	$	0.99	$	1.09	$	(0.10	)	(9	)%
General and administrative	$	2,081	$	1,353	$	728		54	%
Depreciation, depletion and amortization (“DD&A”)	$	539	$	455	$	84		18	%
Impairment of oil and gas properties	$	—	$	165	$	(165	)	N/A
Interest expense	$	1,791	$	1,403	$	388		28	%
Write-off of deferred loan costs	$	—	$	5,069	$	(5,069	)	N/A
Australia operations:
Operating revenue	$	2,531	$	1,710	$	821		48	%
Gas volumes (MMcf)	1,505		1,149		356			31	%
Average gas price per Mcf	$	1.68	$	1.49	$	0.19		13	%
Operating expenses	$	1,229	$	978	$	251		26	%
Average lifting cost per Mcf sold	$	0.82	$	0.85	$	(0.03	)	(4	)%
Oil and gas property DD&A	$	488	$	417	$	71		17	%
Other DD&A	$	37	$	25	$	12		48	%
Oil and Gas DD&A rate per Mcf volumes sold	$	0.32	$	0.36	$	(0.04	)	(11	)%
Domestic operations:
Operating revenue	$	2	$	4	$	(2	)	(50	)%
Gas volumes (MMcf)	0.5		0.7		(.2		)	(29	)%
Average gas price per Mcf	$	4.54	$	4.08	$	0.46		11	%
Operating expenses — producing properties	$	1	$	3	$	(2	)	(67	)%
Average lifting cost on producing properties per Mcfe sold	$	2.94	$	3.86	$	(0.92	)	(24	)%
Operating expenses — non-producing properties	$	253	$	275	$	(22	)	(8	)%
Other DD&A	$	14	$	13	$	1		8	%

19

Revenues and Sales Volumes

The Company is currently selling its Australian gas under three contracts to two purchasers. Energex is purchasing gas from the Company under a five-year contract with delivery requirements of up to 15,000 Mcf of gas per day and under a new short-term contract that terminates December 31, 2004. The Company also entered into a one year gas sales contract with Santos QNT Pty Ltd effective July 2004. The Company is actively pursuing long-term and short-term gas contracts to increase gas sales. With the addition of the two new short-term contracts, the Company’s sales increased to 1,505 MMcf for the third quarter in 2004, a 60% increase over the second quarter’s sales of 938 MMcf and a 31% increase over the same period in 2003. Gas revenues in Australia for the third quarter increased by 48% due to higher sales volumes and a 13% increase in average gas prices. Changes in the exchange rate and the addition of a new gas sales contract with higher prices resulted in the increase in average gas prices.

During the third quarter of 2004, the Company had minimal domestic revenue. Domestic revenues and volumes in 2004 and 2003 relate to small, retained interests in properties producing in the Powder River Basin in Wyoming.

Costs and Expenses

Operating expenses in Australia increased 26% due to the addition of a second compressor facility which commenced operations in December 2003 and well workover costs. Australian oil and gas property DD&A expense increased 17% due principally to higher sales volumes.

Domestic operating expenses in the third quarter of 2004 and 2003 are principally attributable to the Lay Creek coal-seam gas project where the wells are in the dewatering phase.

General and administrative (“G&A”) expenses for the third quarter of 2004 increased 54% compared to the same period in 2003, due principally to an increase in legal costs of approximately $583,000 incurred for the Tri-Star litigation. With the execution of the Settlement Agreement with Tri-Star in October 2004, the Company expects legal expenses to be significantly lower in 2005.

Other Income (Expense)

Interest expense increased to $1.8 million from $1.4 million in 2003, due primarily to increased borrowings to fund operations and capital expenditures. As of September 30, 2004, the Company’s total debt was $94.8 million compared with $58.2 million as of September 30, 2003, an increase of $36.6 million. The interest expense associated with increased borrowings was partially offset by the effect of lower interest rates on TOGA’s long-term debt. As a result of refinancing TOGA’s debt, TOGA’s interest rates decreased from 13% to an average effective rate of 8.725% per annum, which reduced the Company’s total debt effective rate from 12.7% to 9.19%.

In the third quarter of 2003, the Company wrote off $5.1 million in deferred loan costs related to the TCW loan which was retired on August 15, 2003. In accordance with SFAS No. 52, “Foreign Currency Translation” (SFAS 52”), the Company recognized a foreign currency exchange loss of $1.1 million related to the TOGA debt repaid.

Minority Interest in Loss of Subsidiary

During the third quarter of 2004, the Company recognized 100% of TOGA’s net loss as the minority interest in TOGA’S net equity had been reduced to zero at June 30, 2004.

20

Results of Operations - Comparison of the Nine Months Ended September 30, 2004 and 2003

Unless otherwise indicated, the discussion below compares the nine months ended September 30, 2004 to the nine months ended September 30, 2003. The Company incurred a net loss of $11.3 million compared to a net loss of $13.1 million. A 10% increase in revenues was offset by increases in operating costs and general and administrative expenses. Increased debt to fund property exploration and development caused interest expense to increase. An additional expense attributed to the write-off of deferred loan costs partially offset by a foreign currency exchange gain was recorded in 2003. The table below provides a comparison of operations. It is intended to provide a comparative review of significant operational items. Accordingly, nominal differences may exist from the amounts presented in the accompanying Consolidated Financial Statements.

	Nine Months Ended September 30,				Increase			% Increase
	2004		2003		(Decrease)			(Decrease)
	($ in thousands, except average per Mcf prices and costs)
Worldwide operations:
Operating revenue	$	5,263	$	4,764	$	499		10	%
Gas volumes (MMcf)	3,095		3,332		(237		)	(7	)%
Average gas price per Mcf	$	1.70	$	1.43	$	0.27		19	%
Operating expenses	$	4,124	$	3,320	$	804		24	%
Average lifting cost per Mcf equivalent (“Mcfe”) sold	$	1.33	$	1.00	$	.33		33	%
General and administrative	$	5,635	$	4,165	$	1,470		35	%
Depreciation, depletion and amortization (“DD&A”)	$	1,146	$	1,161	$	(15	)	(1	)%
Impairment of oil and gas properties	$	150	$	2,386	$	(2,236	)	(94	)%
Interest expense	$	6,024	$	3,883	$	2,141		55	%
Write-off of deferred loan costs	$	—	$	5,069	$	(5,069	)	N/A
Australia operations:
Operating revenue	$	5,256	$	4,753	$	503		11	%
Gas volumes (MMcf)	3,093		3,330		(237		)	(7	)%
Average gas price per Mcf	$	1.70	$	1.43	$	0.27		19	%
Operating expenses	$	3,394	$	2,660	$	734		28	%
Average lifting cost per Mcf sold	$	1.10	$	0.80	$	0.30		38	%
Oil and Gas property DD&A	$	998	$	1,070	$	(72	)	(7	)%
Other DD&A	$	106	$	53	$	53		100	%
Oil and Gas DD&A rate per Mcf volumes sold	$	0.32	$	0.32	$	—		—
Domestic operations:
Operating revenue	$	7	$	11	$	(4	)	(36	)%
Gas volumes (MMcf)	2		2		—			—
Average gas price per Mcf	$	4.19	$	3.99	$	0.20		5	%
Operating expenses — producing properties	$	4	$	6	$	(2	)	(33	)%
Average lifting cost on producing properties per Mcfe sold	$	2.49	$	2.58	$	(0.09	)	(3	)%
Operating expenses — non-producing properties	$	726	$	654	$	72		11	%
Impairment of oil and gas properties	$	150	$	2,386	$	(2,236	)	(94	)%
Other DD&A	$	42	$	38	$	4		11	%

21

Revenues and Sales Volumes

The Company is currently selling its Australian gas under three contracts to two purchasers. Energex is purchasing gas from the Company under a five-year contract with delivery requirements of up to 15,000 Mcf of gas per day and under a new short-term contract that terminates December 31, 2004. The Company entered into a one year gas sales contract with Santos QNT Pty Ltd. effective July 2004. The addition of two new gas sales contracts effective July 2004 increased gas sales for the third quarter 2004 by 31% over the same period in 2003 and minimized the decline in gas volumes sold in Australia to 7% for the nine month period 2004 compared with the same period in 2003. The Company is actively pursuing long-term and short-term gas contracts to increase gas volumes sold. A decrease in volumes sold for the nine month period ended September 30, 2004 compared with the same period in 2003 was offset by a 19% increase in average gas prices. Changes in the exchange rate and the addition of a new gas sales contract with higher prices resulted in the increase in average gas prices.

During the first nine months of 2004, the Company had minimal domestic revenue. Domestic revenues and volumes in 2004 and 2003 relate to small, retained interests in properties producing in the Powder River Basin in Wyoming.

Costs and Expenses

Operating expenses in Australia increased 28% due to an increase in the number of producing wells, increased well workover costs, gas transportation expense and the addition of a second compressor facility which commenced operations in December 2003. Australian oil and gas property DD&A expense decreased 7% due principally to lower sales volumes.

Domestic operating expenses in the first nine months of 2004 and 2003 were principally attributable to the Lay Creek coal-seam gas project where the wells are in the dewatering phase.

The impairment expense of $150,000 was attributed to unsuccessful exploration costs incurred on wells on the Frenchman prospect.  Impairment expense of approximately $2.4 million in 2003 was attributed largely to unsuccessful exploration on the Nine Mile prospect.

General and administrative (“G&A”) expenses for the first nine months of 2004 increased 35% compared to the same period in 2003 due principally to an increase in legal costs of approximately $828,000 for the Tri-Star litigation and higher employee and consulting costs associated with managing the Comet Ridge properties. With the execution of the Settlement Agreement with Tri-Star in October 2004, the Company expects legal expenses to be significantly lower in 2005.

Other Income (Expense)

Interest expense increased to $6.0 million from $3.9 million, due primarily to increased borrowings to fund operations and capital expenditures. As of September 30, 2004, the Company’s total debt was $94.8 million compared with $58.2 million as of September 30, 2003, an increase of $36.6 million. The interest expense associated with increased borrowings was partially offset by the effect of lower interest rates on TOGA’s long-term debt. As a result of refinancing TOGA’s debt, TOGA’s interest rates decreased from 13% to an average effective rate of 8.725% per annum, which reduced the Company’s total debt effective rate from 12.7% to 9.19%.

In the first nine months of 2003, the Company wrote off $5.1 million in deferred loan costs related to TCW loan which was retired on August 15, 2003. In accordance with SFAS No. 52, the Company recognized a foreign currency exchange gain of $2.1 million related to the TOGA debt repaid.

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Critical Accounting Policies

The Company’s financial statements are based on the selection and application of significant accounting policies, some of which require management to make estimates and assumptions which affect the reported amounts of assets, liabilities, revenues and expenses and also affect the disclosure of contingent items. A summary of the Company’s significant accounting policies is included in Item 7 of the Company’s annual report on Form 10-K for the year ended December 31, 2003. The Company believes that the significant accounting policies discussed therein are some of the more critical judgment areas in application of its accounting policies that currently affect its financial condition and results of operations.

Off-balance Sheet Arrangements

We do not currently have and have never had any relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purposes entities, which typically are established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes.  Further,  we have not guaranteed any obligations of unconsolidated entities nor do we have any commitment or intent to provide funding to any such entities.  Accordingly, we are not materially exposed to any financing, liquidity, market or credit risk that could arise if we had engaged in these relationships.

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Item 3.    Quantitative and Qualitative Disclosure About Market Risk

Market risk is the potential loss arising from adverse changes in market rates and prices, such as foreign currency exchange, interest rates and commodity prices. The Company does not use financial instruments to any degree to manage foreign currency, interest rate or commodity risk and does not hold or issue financial instruments to any degree for trading purposes. Our Australian debt facility has a variable interest rate. Fluctuations in the interest rate could increase or decrease our interest expense. At September 30, 2004, we had approximately $76.5 million ($107.0 million AUD) in outstanding variable rate debt. If the interest rate for our variable rate debt increased or decreased by 1%, our annual interest expense would increase or decrease by approximately $760,000. In addition, at September 30, 2004, the Company was exposed to some market risk with respect to foreign currency and natural gas prices; however, management does not believe such risk to be material.

Item 4.    Controls and Procedures

As of the end of the period covered by this report, we evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures over financial reporting pursuant to Rule 13a-15 and 15d-15 of the Securities Exchange Act of 1934. Based upon that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures over financial reporting are adequate and effective at the reasonable assurance level in timely alerting them to material information required to be included in this quarterly report on Form 10-Q.

Disclosure controls and procedures, no matter how well designed and implemented, can provide only reasonable assurance of achieving an entity’s disclosure objectives. The likelihood of achieving such objectives is affected by limitations inherent in disclosure controls and procedures. These limitations include the fact that human judgment in decision-making can be faulty and that breakdowns in internal control can occur because of human failures such as simple errors or mistakes or because of intentional circumvention of the established process.

During the period covered by this report, there have been no changes in our internal controls over financial reporting or in other factors, which could significantly affect internal controls over financial reporting.

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PART II - OTHER INFORMATION

Item 1.    Legal Proceedings

                See Note 6 to the Consolidated Financial Statements under Part I - Item 1.

Item 2.    Changes in Securities

During the quarterly period ended September 30, 2004, the Company sold and issued two million shares of its common stock in a private placement to 11 unaffiliated institutional investors for $4.00 per share. The issuance of these securities was deemed to be exempt from registration under Section 4(2) of the Securities Act of 1933 as a transaction by an issuer not involving a public offering. The offerees and purchasers were institutional investors who represented that they were purchasing the shares for investment purposes and acknowledged that the certificates in respect of the shares would be affixed with a restrictive legend.

Item 6.    Exhibits

(a)           Exhibits:

Filed herewith

31.1         Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002.

31.2         Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002.

32.1         Certification of Chief Executive Officer of Tipperary Corporation Pursuant to 18 U.S.C. §1350.

32.2         Certification of Chief Financial Officer of Tipperary Corporation Pursuant to 18 U.S.C. §1350.

The other exhibits of the Company are incorporated herein by reference to the exhibit list in the Company’s Annual Report on Form 10-K for the year ended December 31, 2003.

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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:	December 10, 2004	By:	/s/ David L. Bradshaw
			David L. Bradshaw, President, Chief Executive Officer and Chairman of the Board of Directors
Date:	December 10, 2004	By:	/s/ Joseph B. Feiten
			Joseph B. Feiten, Chief Financial Officer and Principal Accounting Officer

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EXHIBIT INDEX

31.1         Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002.

31.2         Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002.

32.1         Certification of Chief Executive Officer of Tipperary Corporation Pursuant to 18 U.S.C. §1350.

32.2         Certification of Chief Financial Officer of Tipperary Corporation Pursuant to 18 U.S.C. §1350.

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