Tipperary (TPY) 10-Q 2005 Q2 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

ý	QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended June 30, 2005
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 1800
Denver, Colorado	80202
(Address of principal executive offices)	(Zip Code)
(303) 293-9379
(Issuer’s telephone number)

Indicate by check mark whether the registrant (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

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

Class	Outstanding at August 10, 2005
Common Stock, $.02 par value	41,414,394 shares

TIPPERARY CORPORATION AND SUBSIDIARIES

Index to Form 10-Q

PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Balance Sheets June 30, 2005 and December 31, 2004
	Consolidated Statements of Operations Three and six months ended June 30, 2005 and 2004
	Consolidated Statements of Stockholders’ Equity Six months ended June 30, 2005 and 2004
	Consolidated Statements of Cash Flows Six months ended June 30, 2005 and 2004
	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.	Unregistered Sales of Equity Securities and Use of Proceeds
Item 6.	Exhibits
SIGNATURES
EXHIBIT INDEX

PART I - FINANCIAL INFORMATION

Item 1.  Financial Statements

TIPPERARY CORPORATION AND SUBSIDIARIES

Consolidated Balance Sheets

(dollars in thousands)

(unaudited)

	June 30, 2005			December 31, 2004
ASSETS
Current assets:
Cash and cash equivalents	$	447		$	3,698
Receivables	2,362			2,156
Other current assets	167			436
Total current assets	2,976			6,290
Property, plant and equipment, at cost:
Oil and gas properties, full cost method:
Proved	130,574			125,195
Unproved	25,086			19,946
Other property and equipment	4,039			3,943
	159,699			149,084
Less accumulated depreciation, depletion and amortization	(11,113		)	(9,833		)
Property, plant and equipment, net	148,586			139,251
Debt issuance costs	4,690			4,661
Other noncurrent assets	445			482
	$	156,697		$	150,684
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	9,400		$	—
Accounts payable	3,068			1,664
Accrued liabilities	3,930			1,881
Royalties payable	208			193
Total current liabilities	16,606			3,738
Long-term debt-related parties	13,000			17,000
Long-term debt	95,717			91,352
Other long-term liabilities	1,006			273
Commitments and contingencies (Note 6)
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; 41,380,594 and 41,365,994 shares issued and 41,370,994 and 41,355,994 shares outstanding as of June 30, 2005 and December 31, 2004, respectively	828			827
Capital in excess of par value	158,464			158,360
Accumulated deficit	(136,206		)	(128,653		)
Accumulated other comprehensive income	7,307			7,812
Treasury stock, at cost; 9,600 shares	(25		)	(25		)
Total stockholders’ equity	30,368			38,321
	$	156,697		$	150,684

See accompanying notes to Consolidated Financial Statements.

1

TIPPERARY CORPORATION AND SUBSIDIARIES

Consolidated Statements of Operations

(in thousands, except per share data)

(unaudited)

	Three months ended June 30,						Six months ended June 30,
	2005			2004			2005			2004
Revenues	$	3,199		$	1,562		$	6,574		$	2,730
Costs and expenses:
Operating	2,357			1,247			4,362			2,641
Depreciation, depletion and amortization	666			356			1,370			607
Asset retirement obligation accretion	9			9			18			18
Impairment of oil and gas properties	—			—			—			150
General and administrative	1,749			1,510			3,937			3,554
Total costs and expenses	4,781			3,122			9,687			6,970
Operating loss	(1,582		)	(1,560		)	(3,113		)	(4,240		)
Other income (expense):
Interest and other income	41			69			80			107
Interest expense	(2,345		)	(2,097		)	(4,519		)	(4,233		)
Other expense	(6		)	(6		)	(1		)	(9		)
Total other income (expense)	(2,310		)	(2,034		)	(4,440		)	(4,135		)
Loss before income taxes	(3,892		)	(3,594		)	(7,553		)	(8,375		)
Income tax benefit	—			—			—			—
Loss before minority interest	(3,892		)	(3,594		)	(7,553		)	(8,375		)
Minority interest in loss of subsidiary	—			63			—			418
Net loss	$	(3,892	)	$	(3,531	)	$	(7,553	)	$	(7,957	)
Net loss per share basic and diluted	$	(.09	)	$	(.09	)	$	(.18	)	$	(.20	)
Weighted average shares outstanding basic and diluted	41,365			39,325			41,361			39,308

See accompanying notes to Consolidated Financial Statements.

2

TIPPERARY CORPORATION AND SUBSIDIARIES

Consolidated Statements of Stockholders’ Equity

(in thousands)

(unaudited)

	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, 2003	39,221	$	785	$	149,970	$	(113,315	)	$	7,094		10	$	(25	)	$	44,509
Warrants granted for services	—	—		66		—			—			—	—			66
Common stock issued:
Stock options exercised	105	2		285		—			—			—	—			287
Comprehensive loss:
Net loss	—	—		—		(7,957		)	—			—	—			(7,957		)
Foreign currency translation adjustment	—	—		—		—			(2,545		)	—	—			(2,545		)
Total comprehensive loss																(10,502		)
Balance at June 30, 2004	39,326	$	787	$	150,321	$	(121,272	)	$	4,549		10	$	(25	)	$	34,360
Balance at December 31, 2004	41,356	$	827	$	158,360	$	(128,653	)	$	7,812		10	$	(25	)	$	38,321
Warrants granted for services	—	—		12		—			—			—	—			12
Common stock issued:
Stock options exercised	15	1		92		—			—			—	—			93
Comprehensive loss:
Net loss	—	—		—		(7,553		)	—			—	—			(7,553		)
Foreign currency translation adjustment	—	—		—		—			(505		)	—	—			(505		)
Total comprehensive loss																(8,058		)
Balance at June 30, 2005	41,371	$	828	$	158,464	$	(136,206	)	$	7,307		10	$	(25	)	$	30,368

See accompanying notes to Consolidated Financial Statements.

3

TIPPERARY CORPORATION AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(in thousands)

(unaudited)

	Six months ended June 30,
	2005			2004
Cash flows from operating activities:
Net loss	$	(7,553	)	$	(7,957	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization	1,370			607
Amortization of debt issuance costs	569			197
Warrants granted for services	12			66
Minority interest in loss of subsidiary	—			(418		)
Asset retirement obligation accretion	18			18
Impairment of oil and gas properties	—			150
Accrued interest added to principal	1,281			—
Changes in current assets and current liabilities:
(Increase) decrease in receivables	(206		)	241
Decrease in other current assets	299			120
Increase (decrease) in accounts payable and accrued liabilities	392			(149		)
Increase in royalties payable	15			2
Net cash used in operating activities	(3,803		)	(7,123		)
Cash flows from investing activities:
Capital expenditures	(9,832		)	(9,431		)
Net cash used in investing activities	(9,832		)	(9,431		)
Cash flows from financing activities:
Proceeds from exercise of common stock options	93			287
Proceeds from borrowings	11,028			86,436
Principal repayments	(704		)	(68,190		)
Debt issuance costs and other	(6		)	(3,313		)
Net cash provided by financing activities	10,411			15,220
Effect of exchange rate changes on cash	(27		)	(94		)
Net decrease in cash and cash equivalents	(3,251		)	(1,428		)
Cash and cash equivalents at beginning of period	3,698			2,996
Cash and cash equivalents at end of period	$	447		$	1,568

See accompanying notes to Consolidated Financial Statements.

4

TIPPERARY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 – OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

In this quarterly report on Form 10-Q, unless the context requires otherwise, when we refer to “we,” “us,” “our,” “Tipperary,” and “the Company,” we are describing Tipperary Corporation and its subsidiaries on a consolidated basis.

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 at June 30, 2005, and the results of their operations for the three-month and six-month periods ended June 30, 2005 and 2004 and their cash flows for the six-month periods ended June 30, 2005 and 2004. The Consolidated Financial Statements include the accounts of Tipperary Corporation and its wholly-owned subsidiaries, Tipperary Oil and Gas Corporation, Tipperary CSG, Inc., Tipperary Queensland, Inc. and Burro Pipeline Corporation, and its 90%-owned subsidiary, Tipperary Oil and Gas (Australia) Pty Ltd (“TOGA”).  All intercompany transactions and balances have been eliminated in consolidation.  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, 2004.  These financial statements should be read in conjunction with the Form 10-K.

Impact of New Accounting Pronouncements

In June 2005, the FASB issued Statement No. 154, “Accounting Changes and Error Corrections – A replacement of APB No. 20 and FASB Statement No. 3”  (“SFAS 154”).  SFAS 154 provides guidance on the accounting for and reporting of error corrections, changes in accounting principles and changes in accounting estimates.  It establishes restatement as the required method for reporting error corrections.  It establishes retrospective application (unless impracticable) for reporting changes in accounting principle in the absence of explicit transition requirements specific to the newly adopted accounting principle.  For a restatement, a presentation of current and prior period financial statements shows each presented statement corrected for any errors in that statement in previous presentations.  For retrospective application, each presented statement reflects the change in accounting principle as if the change had occurred prior to the presented periods.  A current change in accounting estimate is not treated retrospectively, but prospectively beginning with the current period.  SFAS 154 is required to be adopted in fiscal years beginning after December 15, 2005.  The Company does not believe its adoption will have a material impact on its financial statements.

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligation” (“FIN 47”).  This Interpretation clarifies the definition and treatment of conditional asset retirement obligations as discussed in FASB Statement No. 143, “Accounting for Asset Retirement Obligations.”  A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside the control of a company.  FIN 47 states that a company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable.  This Interpretation is intended to provide more information about long-lived assets, more information about future cash outflows for these obligations and more consistent recognition of these liabilities.  FIN 47 is effective for fiscal years ending after December 15, 2005.  The Company does not believe that its financial position, results of operations or cash flows will be impacted by this Interpretation.

In December 2004, the FASB issued a revision to SFAS No. 123, “Accounting for Stock-Based Compensation,” SFAS No. 123R, “Share-Based Payment.” SFAS No. 123R focuses primarily on transactions in which an entity exchanges its equity instruments for employee services and generally establishes standards for the accounting for transactions in which an entity obtains goods or services in share-based payment transactions and is required to expense the value of employee stock options and similar awards.  The Securities and Exchange Commission recently delayed the implementation date for this pronouncement.  We now expect to adopt SFAS No. 123R effective January 1, 2006 using the modified prospective application.  We do not expect SFAS No. 123R to have a material effect on our financial position, results of operations or cash flows.

We have reviewed all other recently issued, but not yet adopted, accounting standards in order to determine their effects, if any, on our results of operations or financial position.  Based on that review, we believe that none of these pronouncements will have a significant effect on our current or future financial position or results of operations.

5

Revenue Recognition and Gas Imbalances

The Company recognizes natural gas revenue from its interests in producing wells as natural gas is 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. If excess takes of natural gas exceed the Company’s remaining proved reserves for the property, it records a natural gas imbalance in other liabilities.  As of June 30, 2005, the Company had taken and sold more than its share of natural gas volumes produced from the Comet Ridge project and was overproduced by approximately 1,636 MMcf (net of royalties). Based on the June 30, 2005 average sales price of $1.92 per Mcf, this overproduction represents approximately $3.2 million in gas revenues. At June 30, 2005, no liability has been recorded for the excess volumes taken, as they did 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 TOGA’s entitled share of sales, to enable underproduced parties to sell more than their entitled share of the gas sales and cure the imbalance.

Stock-Based Compensation

SFAS No. 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 June 30, 2005, 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 a director or employee must pay to acquire the stock.  Pro forma results as if the Company had adopted the cost recognition provisions of SFAS Nos. 148 and 123 are presented below:

	Three Months Ended June 30,
	2005			2004
	(in thousands, except per share data)
Net loss, as reported	$	(3,892	)	$	(3,531	)
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	(114		)	(13		)
Pro forma net loss	$	(4,006	)	$	(3,544	)
Loss per share
Basic and diluted—as reported	$	(.09	)	$	(.09	)
Basic and diluted—pro forma	$	(.10	)	$	(.09	)

6

	Six Months Ended June 30,
	2005			2004
	(in thousands, except per share data)
Net loss, as reported	$	(7,553	)	$	(7,957	)
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	(231		)	(29		)
Pro forma net loss	$	(7,784	)	$	(7,986	)
Loss per share
Basic and diluted—as reported	$	(.18	)	$	(.20	)
Basic and diluted—pro forma	$	(.19	)	$	(.20	)

Foreign Currency

The functional currency of TOGA is the Australian dollar. As the functional currency is the local currency, the current rate method is used to translate TOGA’s Australian dollar financial statements into U.S. dollars. 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 because of the Company’s net operating loss carryforwards) as of June 30, 2005 and December 31, 2004 totaled $7.3 million and $7.8 million, respectively.

Liquidity and Operations

In July 2005, the Company’s majority shareholder, Slough Estates USA Inc. (“Slough”), sold all of its ownership interest in the Company.  Santos International Holdings Pty Ltd (“Santos”) acquired Slough’s ownership interest and assumed Slough’s commitment to provide funding to the Company.  The Company anticipates funding operations and capital expenditures in Australia and the United States for 2005 using (a) cash on hand at June 30, 2005, (b) net gas revenues, (c) approximately $18 million ($23 million AUD) in available long-term borrowings from the Company’s Australian senior credit facility and (d) a commitment from Santos to provide funds for operations, working capital and board-approved capital expenditures through April 2006.

The Company anticipates having sufficient production history from its Frenchman and Republican project wells by late 2005 to allow the Company to support a limited amount of borrowing for further development of these projects or partial repayment of existing Santos debt. In order to fund discretionary United States capital expenditures in 2005 in excess of these cash resources, the Company anticipates that it will require alternative sources of capital. Additional sources of funding may include additional debt financings and asset sales.  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.

7

NOTE 2 - RELATED PARTY TRANSACTIONS

At June 30, 2005, the Company owed Slough and Slough Trading Estate Limited (“STEL”), a United Kingdom company that is the parent of Slough, $22.4 million.  In July 2005, Santos acquired Slough’s ownership interest in the Company and under the terms of the acquisition agreement, its parent company, Santos Limited, has assumed Slough and STEL’s debt and guarantee arrangements with the Company.  Santos plans to acquire the remainder of outstanding shares in the Company early in the 4^th quarter of 2005 (See Note 10).

As of June 30, 2005, the Company had one credit facility agreement with STEL, subsequently with Santos, with an outstanding balance of $13.0 million. No additional funds may currently be borrowed under this facility.  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.  Santos may demand repayment prior to the maturity date on 18-months notice.  So long as the Santos indebtedness exists, the Company may not obtain any additional third party indebtedness, either secured or unsecured, or make a priority payment on any obligation, without first obtaining written approval from Santos.

In 2002 and in the first six months of 2005, the Company borrowed $4 million and $5.4 million, respectively, from Slough which is evidenced by a note payable dated May 13, 2005 that bears interest at LIBOR plus 3.5% (6.64% as of June 30, 2005) and is payable to Santos in full on April 30, 2006.

Santos Limited has assumed Slough’s obligation to guarantee, for a period up to five years through June 2009, the Company’s $150.0 million AUD bank credit facility that closed in June 2004.  As consideration for the guarantee, the Company pays 1% per annum to Santos Limited on the daily outstanding balance of the debt guaranteed.  For the three-month period ended June 30, 2005, the Company paid guarantee fees of $230,000 to Slough.

For the three month periods ended June 30, 2005 and 2004, approximately $545,000 and $2.3 million, respectively, in interest and fees were paid collectively to Slough and STEL under the financing agreements discussed herein.

Santos has committed to provide funds to the Company in the form of long-term loans or equity contributions through April 2006 to be used for operations, working capital and board-approved capital expenditures.

NOTE 3—COMET RIDGE PROJECT FINANCING

On June 9, 2004, TOGA entered into a $150.0 million AUD senior credit facility agreement comprised of a recourse portion and a non-recourse portion with two major Australian financial institutions for the purpose of paying in full TOGA’s borrowings of $100.0 million AUD from STEL and to fund TOGA’s operations 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 portions beginning in 2007 and concluding in 2014.  The interest rate for the facility (6.60% per annum as of June 30, 2005) varies with the Australian inter-bank rate plus other factors.  Commitment fees of 0.425% per annum of committed but undrawn funds, as defined by the credit facility, are payable semi-annually.  The facility is collateralized by, among other things, TOGA’s common stock and virtually all of the Company’s consolidated interest in the Comet Ridge project and is guaranteed through June 9, 2009 by Santos.  The facility contains certain restrictive covenants, including maintenance of certain ratios. While Santos’ parent Santos Limited is guaranteeing the full debt, as Slough was at June 30, 2005, the Company’s covenant obligations relate primarily to reporting requirements.  At June 30, 2005, the Company had met all required covenants.  When all or a portion of the debt is no longer guaranteed, the Company will be obligated to maintain certain financial ratios in addition to the current reporting requirement covenants.  The U.S. dollar value of the outstanding balance of this facility as of June 30, 2005 was approximately $95.7 million (approximately $125 million AUD), including interest due which will be paid with funds borrowed from the facility of $1.3 million (approximately $1.7 million AUD).  TOGA incurred approximately $5.0 million in debt issuance costs on this facility, which TOGA has deferred and is amortizing over five years. TOGA has accrued an additional $683,000 for the present value of deferred underwriting fees to be paid by June 9, 2009.  These costs relate to future loan underwriting fees the Company will pay upon conversion of the senior credit facility from recourse to non-recourse debt.  During the six-month period ended June 30, 2005, TOGA incurred interest and commitment fees of approximately $3.0 million and $47,000, respectively on this facility which includes $1.3 million of accrued interest to the principal of this facility.

8

NOTE 4 - 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 June 30,
	2005			2004
Numerator:
Net loss	$	(3,892	)	$	(3,531	)
Denominator:
Weighted-average shares outstanding	41,365			39,325
Effect of dilutive securities:
Assumed exercise of dilutive options and warrants	—			—
Weighted-average shares and dilutive potential common shares	41,365			39,325
Basic and diluted loss per share	$	(.09	)	$	(.09	)
Total options and warrants which could potentially dilute basic EPS in future periods	3,854			3,518

	Six Months Ended June 30,
	2005			2004
Numerator:
Net loss	$	(7,553	)	$	(7,957	)
Denominator:
Weighted-average shares outstanding	41,361			39,308
Effect of dilutive securities:
Assumed exercise of dilutive options and warrants	—			—
Weighted-average shares and dilutive potential common shares	41,361			39,308
Basic and diluted loss per share	$	(.18	)	$	(.20	)
Total options and warrants which could potentially dilute basic EPS in future periods	3,854			3,518

9

NOTE 5 –MINORITY INTEREST IN TOGA

For the six months ended June 30, 2005, the 10% minority interest share of TOGA’s net loss totaled $417,000.  As the minority interest in TOGA’s net equity (excluding the cumulative foreign currency translation adjustment), at December 31, 2004 was zero, the Company recognized 100% of TOGA’s net loss for the six months ended June 30, 2005.  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.  Such share totaled $1.2 million at June 30, 2005.

NOTE 6 - COMMITMENTS AND CONTINGENCIES

The Company’s business activities are subject to federal, state and local environmental laws and regulations as well as similar laws and regulations in the Commonwealth of Australia and the State of Queensland, Australia. In the fourth quarter of 2003, the Queensland government notified the Company that exploration and production of gas from under national park lands would be limited to using surface facilities located outside the parks, subject to changes in the national park boundaries in the vertical plane allowing for horizontal drilling.  If gas reserves are discovered under park lands, they would be recovered to the extent possible using directional drilling from drill sites adjacent to park lands. Directional drilling is currently used to produce some coalseam and conventional gas in the U.S. and Australia.  Management believes the technique can be used effectively at Comet Ridge to recover a substantial portion of any reserves that ultimately would have been recoverable from drilling within the parks.  During the first six months of 2005, the Company has drilled two horizontal wells and is evaluating the effectiveness of the drilling.  Management does not expect these new requirements to significantly increase future exploration, development and operating costs per Mcf sold. Three of the Company’s productive wells and one ATP 526 exploration well were previously permitted on park lands. Under current government policy, the four wells are to be plugged and abandoned, and the surface area reclaimed at an estimated cost to the Company of $100,000. The Company expects to recover these wells’ reserves using directional drilling. The amount of any reserves that may ultimately be determined to be under park lands is not currently known. The Company will continue to monitor environmental compliance. There can be no assurance that environmental laws and regulations will not become more stringent in the future or that the Company will not incur significant costs in the future to comply with such laws and regulations.

The Company is subject to various other possible contingencies which arise primarily from interpretation of federal and state laws and regulations affecting the oil and gas industry. Although management believes it has complied with the various laws and regulations, administrative rulings and interpretations thereof, additional costs could be incurred as new interpretations and regulations are issued.

10

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 expense, interest expense, interest and other income and other expense are not allocated to segments.  The Company’s Chief Executive Officer, or primary decision maker, reviews management reports in the segments as presented in the tables below.  The segment data presented below was prepared on the same basis as the Company’s Consolidated Financial Statements.  Reportable business segment information as of June 30, 2005 and 2004, and for the three and six months ended June 30, 2005 and 2004 is as follows (in thousands):

As of and for the three months ended June 30, 2005

	Gas and Oil Operations							Non-
	Australia		United States			Total		Segmented Items(1)			Total
Revenues	$	2,992	$	207		$	3,199	$	—		$	3,199
Income (loss) before income taxes	$	382	$	(131	)	$	251	$	(4,143	)	$	(3,892	)
Property, plant and equipment, net	$	133,472	$	14,597		$	148,069	$	517		$	148,586
Total assets	$	136,275	$	15,215		$	151,490	$	5,207		$	156,697

(1)  Loss before income taxes for non-segmented items includes $1.7 million of general and administrative expenses, $49,000 of corporate depreciation and $2.3 million of interest expense.  Property, plant and equipment, net, includes $517,000 of corporate office equipment, computer hardware and software.  In addition to corporate property, plant and equipment, total assets include debt issuance costs of $4.7 million.

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

	Gas and Oil Operations								Non-
	Australia		United States			Total			Segmented Items(1)			Total
Revenues	$	1,560	$	2		$	1,562		$	—		$	1,562
Income (loss) before income taxes	$	188	$	(224	)	$	(36	)	$	(3,558	)	$	(3,594	)
Property, plant and equipment, net	$	108,036	$	8,466		$	116,502		$	401		$	116,903
Total assetsq	$	111,612	$	8,590		$	120,202		$	4,461		$	124,663

(1)  Loss before income taxes for non-segmented items includes $1.5 million of general and administrative expenses and $2.1 million of interest expense.  Property, plant and equipment, net, includes $401,000 of corporate office equipment, computer hardware and software.  In addition to corporate property, plant and equipment, total assets include debt issuance costs of $4.1 million.

11

As of and for the six months ended June 30, 2005

	Gas and Oil Operations							Non-
	Australia		United States			Total		Segmented Items(1)			Total
Revenues	$	6,366	$	208		$	6,574	$	—		$	6,574
Income (loss) before income taxes	$	1,526	$	(526	)	$	1,000	$	(8,553	)	$	(7,553	)
Property, plant and equipment, net	$	133,472	$	14,597		$	148,069	$	517		$	148,586
Total assets	$	136,275	$	15,215		$	151,490	$	5,207		$	156,697

(1)  Loss before income taxes for non-segmented items includes $3.9 million of general and administrative expenses, $97,000 of corporate depreciation and $4.5 million of interest expense.  Property, plant and equipment, net, includes $517,000 of corporate office equipment, computer hardware and software.  In addition to corporate property, plant and equipment, total assets include debt issuance costs of $4.7 million.

As of and for the six months ended June 30, 2004

	Gas and Oil Operations									Non-
	Australia			United States			Total			Segmented Items(1)			Total
Revenues	$	2,726		$	4		$	2,730		$	—		$	2,730
Loss before income taxes	$	(28	)	$	(630	)	$	(658	)	$	(7,717	)	$	(8,375	)
Property, plant and equipment, net	$	108,036		$	8,466		$	116,502		$	401		$	116,903
Total assets	$	111,612		$	8,590		$	120,202		$	4,461		$	124,663

(1)Loss before income taxes for non-segmented items includes $3.6 million of general and administrative expenses and $4.2 million of interest expense.  Property, plant and equipment, net, includes $401,000 of corporate office equipment, computer hardware and software.  In addition to corporate property, plant and equipment, total assets include debt issuance costs of $4.1 million.

NOTE 8– PROPERTY, PLANT AND EQUIPMENT

A summary of property, plant and equipment follows:

	June 30, 2005			December 31,2004
	(in thousands)
Proved and evaluated oil and gas properties:
Australian properties	$	128,047		$	121,376
Domestic properties	2,527			2,068
Unproved oil and gas properties (excluded from amortization):
Australian properties	12,997			13,236
Domestic properties	12,089			8,461
Oil and gas properties	155,660			145,141
Other property and equipment	4,039			3,943
	159,699			149,084
Less accumulated depreciation, depletion and amortization	(11,113		)	(9,833		)
Property, plant and equipment, net	$	148,586		$	139,251

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NOTE 9 – STATEMENT OF CASH FLOWS SUPPLEMENTAL INFORMATION

	Six Months Ended June 30,
	2005		2004
	(in thousands)
Cash paid during the period for interest	$	3,584	$	4,779
Non-cash investing and financing activities—
Net increase in payables for capital expenditures	$	2,336	$	702
Increase in other long-term liabilities for debt issuance costs	$	670	$	36

NOTE 10 - SUBSEQUENT EVENTS

On July 1, 2005, Santos, a company incorporated in the Australian Capital Territory, and Slough Estates plc, a United Kingdom public limited company (“Slough Estates”), entered into an Interest Purchase Agreement which was amended on July 4, 2005.  Under the July 4^th Amended and Restated Interest Purchase Agreement (the “Amended IPA”), Santos agreed to acquire 100% of the interests in the Company held by Slough, Slough Estates and STEL.  On July 13, 2005, the parties completed the closing of the transactions contemplated by the Amended IPA, and Santos acquired the ownership held by Slough of approximately 54% of the outstanding common stock of Tipperary Corporation for a purchase price of $7.39 per share, Slough’s warrants for 1,700,000 additional shares of the Company’s common stock, as well as Slough’s 10% interest in TOGA, and assumed the position of Slough Estates, Slough and STEL, as creditors, respectively, of the Company.  Santos’ parent company, Santos Limited, also assumed Slough’s obligations as guarantor of the $150 million AUD senior credit facility referenced to in Note 4.  The aggregate purchase price for the Company common stock and other securities and interests purchased by Santos under the Amended IPA was approximately $222,710,273, and was paid entirely in cash.

On July 1, 2005, the Company and Santos entered into an Agreement and Plan of Merger which was amended on July 4, 2005.  Under the July 4^th Amended and Restated Agreement and Plan of Merger (the “Amended Merger Agreement”), the Company agreed to merge with Santos Acquisition Co., a Texas Corporation that is a wholly owned subsidiary of Santos, pending approval by the Company’s shareholders at a special meeting to be called to vote on the merger.  If the merger is approved, Santos will acquire all of the Company’s outstanding stock that it does not already own for $7.43 per share in cash.

On July 13, 2005, upon change of control of the Company, certain employees became eligible for a 35% stay on bonus to be paid on September 30, 2005 unless terminated with cause prior to that date.  The Company expects to record approximately $800,000 for the 35% stay on bonus in the third quarter of 2005.

In July 2005, the Company paid Houlihan Lokey Howard & Zukin $500,000 for a July 3, 2005 written fairness opinion related to the Santos-Tipperary merger.  These fees will be expensed in the third quarter of 2005.

If Tipperary shareholders approve the merger and if Santos closes the merger with arrangements to buy the minority interests at $7.43 per share, then the Company will be obligated to pay a $6 million investment banking commission to Houlihan at closing.  Section 4.19 of the Amended Merger Agreement provides that the fee will not be deducted from the $7.43 per share in payments to the minority shareholders.  It further provides that if Tipperary does not have the funds to pay the fee, Santos will pay the fee.  Santos has indicated orally it will advance funds to Tipperary rather than Santos paying the fee directly.  Since the $6 million fee is contingent on successful merger closing and has not been earned at June 30, no portion of it is accrued at June 30, 2005.

Through the Santos acquisition of Slough’s ownership in the Company Santos has acquired warrants for 1,700,000 shares of Company common stock at an exercise cost of $3,900,000.  In August 2005 Santos indicated to the Company that it plans to exercise those warrants in late August.

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Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations

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 we expect or anticipate 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, we undertake 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 our SEC filings, particularly our Form 10-K for the year ended December 31, 2004, for meaningful cautionary language and discussion of risk factors disclosing why actual results may vary materially from those anticipated by management.

Santos Transaction

The historical financial condition and results of operations through June 30, 2005, are subject to the subsequent events described below:

On July 1, 2005, Santos, a company incorporated in the Australian Capital Territory, and Slough Estates plc, a United Kingdom public limited company (“Slough Estates”), entered into an Interest Purchase Agreement which was amended on July 4, 2005. Under the July 4th Amended and Restated Interest Purchase Agreement (the “Amended IPA”), Santos agreed to acquire 100% of the interests in the Company held by Slough, Slough Estates and STEL. In connection with this transaction the Tipperary board of directors received a fairness opinion for which Tipperary paid $500,000 in late July 2005.  On July 13, 2005, the parties completed the closing of the transactions contemplated by the Amended IPA, and Santos acquired the ownership of approximately 54% of the outstanding common stock of Tipperary Corporation held by Slough for a purchase price of $7.39 per share, as well as Slough’s 10% interest in TOGA, and assumed the position of Slough Estates, Slough and STEL, as guarantor and creditors, respectively, of the Company.  Santos’ parent company, Santos Limited, also assumed Slough’s obligation as guarantor of the $150 million AUD senior credit facility referenced to in Note 4.  The aggregate purchase price for the Company common stock and other securities and interests purchased by Santos under the Amended IPA was approximately $222,710,273, and was paid entirely in cash.

On July 1, 2005, the Company and Santos entered into an Agreement and Plan of Merger which was amended on July 4, 2005.  Under the July 4th Amended and Restated Agreement and Plan of Merger (the “Amended Merger Agreement”), the Company agreed to merge with Santos Acquisition Co., a Texas Corporation that is a wholly owned subsidiary of Santos, pending approval by the Company’s shareholders at a special meeting to be called to vote on the merger.  If the merger is approved, Santos will acquire all of the Company’s outstanding stock that it does not already own for $7.43 per share in cash.  Approval requires that shareholders owning at least 66.7% of the outstanding stock vote in favor of the merger.  Upon successful completion of the merger the Company’s investment banker, Houlihan, Lokey, Howard & Zukin will receive $6 million in commission fees.  Section 4.19 of the Amended Merger Agreement requires that Santos pay the commission fees if Tipperary is unable to do so.  The minority shareholders of the Company have no obligation to pay these commission fees.

Management anticipates that the meeting of shareholders will be held in October 2005. The definitive date of the meeting will be set forth in a Schedule 14A Proxy Statement (“Proxy”) to be mailed to all shareholders of record prior to the meeting date with at least 10 days notice.  On August 11, 2005, the Company filed a preliminary proxy with the SEC.

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Overview

Australia

Our activities in Australia are conducted substantially through our 90%-owned Australian subsidiary, Tipperary Oil & Gas (Australia) Pty Ltd (“TOGA”).  As of June 30, 2005, Tipperary owned a 75.25% undivided capital-bearing interest in the Comet Ridge project in Queensland, Australia.  Of this interest, TOGA holds 65% and other Tipperary entities hold 10.25%.  This project comprises approximately 1,230,500 acres in the Bowen Basin, which includes five petroleum leases (“PL”) covering approximately 287,500 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.  We also hold 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 generally 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.

Upon expiration of an ATP, legislation and policy of the Queensland DNRM allow the ATP holder to apply to renew the ATP for an additional four year period.  ATP 526 was renewed effective November 1, 2004 for another four year exploration term, expiring on October 31, 2008.  No relinquishment was required at the time of renewal, however a series of relinquishments are mandatory during the current term. Recent changes to legislation have changed several fundamental aspects of ATP management, especially those concerning relinquishment and the ability to vary conditions of an ATP.  These changes have also resulted in Tipperary’s acreage being administered under different Acts.  ATP 526, and all the petroleum leases, are administered under the Petroleum Act 1923 as before, except that the Act has been substantially amended effective December 31, 2004.  ATPs 653, 655 and 745, which have initial terms expiring on September 30, 2006, October 31, 2007 and October 31, 2007, respectively, are now administered under the Petroleum and Gas (Production and Safety) Act 2004, which was enacted on December 31, 2004.  These ATPs can be renewed for up to a 12 year period under the new Act.

With respect to ATP 653, we 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. The horizontal well was partially drilled in January 2005, and we anticipate drilling operations to continue in late 2005.  We have completed expenditure requirements for ATPs 745 and 655.  The terms of the ATP 526 renewal do not require exploration expenditures during 2005.

Our gas marketing in eastern Australia has been primarily focused on obtaining long-term gas sales agreements that provide five to 15 years of firm sales typically starting in 2006 to 2008.  However, short-term sales contracts have recently been utilized and are being pursued.  During 2004, our Australian natural gas sales were made to four purchasers under various short and long-term contracts.  We are under contract to provide gas volumes to the same four purchasers in 2005.

The following tables summarize gross gas production by quarter and well status on the Comet Ridge project as of June 30, 2005.  We are expanding the capacity of our metering equipment, compressors and facilities to a sales capacity of approximately 45 MMcf per day.  We expect the capacity expansion project to be completed by October 2005.

15

Comet Ridge Operations Review

	For the Quarter Ended
	September 30, 2004	December 31, 2004	March 31, 2005	June 30, 2005
Gross Average Daily Volumes (MMCF)
Sold	23	28	28	27
Flared	2	1	1	2
Used for compression fuel	3	3	3	3
Produced	28	32	32	32

	Number of Wells At June 30, 2005
Well Status
Selling	58
Dewatering or temporarily shut-in	26
Producing	84
Being evaluated	13
Injection/monitoring wells	5
To be plugged and abandoned	3
Plugged and abandoned	3
Total drilled	108

We drilled one exploratory and two development wells on the Comet Ridge project during the first six months of 2005.  Two of these wells were drilled horizontally.  The horizontal development well was successfully completed, and it tested over one million cubic feet of gas per day.  This well is expected to be worked over in the coming weeks as gas production has unexpectedly declined since the initial production tests.  Drilling of the horizontal exploratory well was interrupted by difficulties encountered while drilling.  We expect this well will be re-entered in late 2005.  The 2005 drilling was substantially funded with borrowings from our Australian bank credit facility.

We believe that current and anticipated development drilling programs on the Comet Ridge project will enable us to satisfy our gas supply delivery commitments, although this cannot be assured.

United States

Our assets in the United States consist primarily of natural gas exploration and development leaseholds in Colorado and Nebraska, which are described below by project area.  The four projects in eastern Colorado and western Nebraska principally target conventional, natural gas in the Niobrara formation.

Frenchman — We hold a 25% interest in 159,000 acres and 100% in 3,000 acres in the Frenchman project in eastern Colorado.  The Houston Exploration Company (“Houston Exploration”) holds the remaining 75% interest in the 159,000 acres and is the operator of that portion of the acreage.  As of August 1, 2005, we have drilled a total of 14 wells on the project.  We have successfully completed eleven wells in the 100%-owned area of the project and anticipate we will drill six additional 100%-owned wells in 2005 at a cost to us of approximately $1,200,000.  In February 2005, we completed a gas gathering system at a cost of approximately $350,000.  Our June 2005 net sales volumes were approximately 900 Mcf per day.  Current net gas sales are approximately 1.4 MMcf per day and we expect net sales volumes to increase to 1.6 MMcf in the near term.

16

Republican — We hold a 20% interest in the Republican project in eastern Colorado.  Total gross acreage in this project approximates 170,000 acres. Houston Exploration holds the remaining 80% interest and is the operator of the project.  Through August 8, 2005, a total of 67 wells have been drilled on the project of which 44 wells were completed, 13 wells are scheduled for completion, one was drilled as a salt water disposal well and nine were plugged and abandoned.  In the first six months of 2005, we participated with Houston Exploration in a 3D seismic program covering 99,000 gross acres at a net cost to us of $726,000.  As a result of that survey and drilling success on the Republican project, we may participate in drilling up to 250 wells by the end of 2006.  Gas sales began on the Republican project in late July 2005 at 1.0 MMcf per day.

Lay Creek — We hold a 50% working interest in Lay Creek, a coalseam gas project in western Colorado. The project includes various leasehold interests covering over 92,000 gross acres. Koch Exploration Company (“Koch”) holds the remaining 50% working interest and operates the project.  We are currently evaluating the gas and water production from pilot wells in order to determine economic viability of the production.  We are also showing the acreage to other companies which may have an interest in participating in future drilling.

Stateline — We hold a 25% interest in the Stateline project in western Nebraska.  Total gross acreage in the project is approximately 113,000 acres.  Lance Oil & Gas Company, Inc. (“Lance”) holds the remaining 75% interest and is the operator of the project.  In the first half of 2004, preliminary 2-D seismic operations were conducted at a cost to us of approximately $100,000.  The acquisition of 3D seismic data began in February 2005 at a cost to us of approximately $160,000.  We have identified drill sites through the seismic evaluation and anticipate drilling will begin in the fourth quarter of 2005.

Sand Hill — During late 2003, we acquired leasehold acreage in western Nebraska totaling approximately 51,000 gross acres, called the “Sand Hill” project.  This acreage is located in the vicinity of our Frenchman, Republican and Stateline projects. We currently hold 100% of the acreage but may sell an interest to an industry partner.  Alternatively, we may elect to explore and develop this project independently.  During the fourth quarter of 2004, we conducted limited 2-D seismic operations on the Sand Hill project and are currently evaluating those results.

Financial Condition, Liquidity and Capital Resources

We had cash and cash equivalents of $447,000 as of June 30, 2005, compared to approximately $3.7 million as of December 31, 2004.  We have funded operations and capital expenditures for the six months ended June 30, 2005, using primarily (a) $3.7 million of cash on hand at December 31, 2004, (b) borrowings from our Australian senior credit facility and (c) borrowings from Slough.

In July 2005, the Company’s majority shareholder, Slough, sold all of its ownership interest in the Company.  Santos acquired Slough’s ownership interest and assumed Slough’s commitment to provide funding to the Company.  We anticipate funding operations and capital expenditures in Australia and the United States for 2005 using (a) cash on hand at June 30, 2005, (b) net gas revenues, (c) approximately $18 million ($23 million AUD) in available long term borrowings from our Australian senior credit facility and (d) a commitment from Santos to provide funds for operations, working capital, and board-approved capital expenditures through April 2006.  Through the Santos acquisition of Slough’s ownership in the Company Santos has acquired warrants for 1,700,000 shares of Company common stock at an exercise cost of $3,900,000.  In August 2005 Santos indicated to the Company that it plans to exercise those warrants in late August.

We anticipate having sufficient production history from our Frenchman and Republican project wells by late 2005 to be able to borrow against these assets.  In order to fund discretionary United States capital expenditures in 2005 in excess of these cash resources, we anticipate that we will require alternative sources of capital. Additional sources of funding may include additional debt financings and asset sales.  However, in the event that sufficient funding cannot be obtained, we will be required to curtail planned expenditures and may have to sell additional acreage and/or relinquish acreage.

17

Net cash used by operating activities was $3.8 million during the six months ended June 30, 2005, compared to $7.1 million of cash used during the same period last year.  The decrease in net cash used for operations in the first six months of 2005 compared with the same period in 2004 resulted primarily from higher gas revenues.

The table below provides an analysis of cash used for capital expenditures during the six months ended June 30, 2005.

Capital Expenditures Activity

(in thousands)

Australia:
Comet Ridge drilling and completion	$	4,100
Comet Ridge facilities and equipment	2,005
ATP 655 exploration	301
Other	242
United States:
Republican drilling and completion	980
Frenchman facilities, equipment and drilling	837
Seismic and leasehold acquisition	979
Other	388
Total	$	9,832

Included within the first six months of 2005 capital spending was $467,000 of capitalized interest expense associated with our Australian and United States properties.  Australian and United States capital expenditures for the first six months of 2005 were funded principally under (a) TOGA’s credit facility with Australian financial institutions and (b) borrowing from Slough, respectively.

During the first six months of 2004, capital spending totaled $9.4 million with approximately $7.0 million in capital spending in Australia and the remainder in the United States.  Capital expenditures for the first six months of 2004 were funded principally under TOGA’s credit facility and borrowings from Slough.

The Company has various commitments in addition to its long-term debt.  The following table summarizes the Company’s contractual obligations at June 30, 2005 (in thousands):

Contractual Obligation	Total		2005		2006		2007		2008		Thereafter
Long-term debt(1)	$	118,117	$	—	$	9,400	$	—	$	—	$	108,717
Interest(2)	$	55,680	$	4,316	$	8,320	$	8,428	$	8,640	$	25,976
Operating leases for office space	$	1,439	$	181	$	365	$	372	$	247	$	274
Operating leases for equipment	$	7,311	$	857	$	1,735	$	1,697	$	1,619	$	1,403
Petroleum lease expenditures(3)	$	2,035	$	935	$	550	$	275	$	275	$	—

(1)Senior credit facility and debt payable to Slough and STEL.

(2)Based on June 30, 2005 weighted average interest rate of 6.60% and anticipated debt repayment.

(3)Petroleum lease expenditures can be reduced or eliminated by governmental royalties paid on gas sales.

18

Results of Operations - Comparison of the Three Months Ended June 30, 2005 and 2004

We incurred a net loss of approximately $3.9 million for the three months ended June 30, 2005 compared to a net loss of approximately $3.5 million for the three months ended June 30, 2004.  Higher gas revenues in 2005 were substantially offset by higher operating costs and depreciation, depletion and amortization.  The table below provides a comparison of operations for the three months ended June 30, 2005 with those of the prior year’s three months.  The table 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.  Certain prior period amounts may have been reclassified to ensure comparability.

	Three Months Ended June 30,				Increase			% Increase
	2005		2004		(Decrease)			(% Decrease)
	($ in thousands, except average per Mcf prices and costs)
Worldwide operations:
Gas revenue	$	3,199	$	1,562	$	1,637		105	%
Gas volumes (MMcf)	1,585		938		647			69	%
Average gas price per Mcf	$	2.02	$	1.66	$	0.36		22	%
Operating expenses	$	2,357	$	1,247	$	1,110		89	%
Average operating costs per Mcf sold	$	1.49	$	1.33	$	.16		12	%
General and administrative	$	1,749	$	1,510	$	239		16	%
Depreciation, depletion and amortization (“DD&A”)	$	666	$	356	$	310		87	%
Interest expense	$	2,345	$	2,097	$	248		12	%
Australia operations:
Gas revenue	$	2,992	$	1,560	$	1,432		92	%
Gas volumes (MMcf)	1,551		938		613			65	%
Average gas price per Mcf	$	1.93	$	1.66	$	0.27		16	%
Operating expenses	$	2,041	$	1,025	$	1,016		99	%
Average operating costs per Mcf sold	$	1.32	$	1.09	$	.23		21	%
Oil and Gas property DD&A	$	600	$	308	$	292		95	%
Other DD&A	$	29	$	34	$	(5	)	(15	)%
Oil and Gas DD&A rate per Mcf sold	$	0.36	$	0.33	$	0.03		9	%
United States operations:
Gas revenue	$	207	$	2	$	205		10,250	%
Gas volumes (MMcf)	34		0.5		33.5			6,700	%
Average gas price per Mcf	$	6.09	$	4.08	$	2.01		49	%
Operating expense – producing properties	$	51	$	1	$	50		5,000	%
Average operating costs per Mcf sold(1)	$	1.50	$	2.31	$	(.81	)	(35	)%
Operating expenses – non-producing	$	265	$	221	$	44		20	%
Oil and Gas property DD&A	$	20	$	—	$	20		N/A
Other DD&A	$	17	$	14	$	3		21	%

(1)Average operating costs per Mcf for the quarter is for our producing properties.  To provide a more meaningful comparison of operating costs per Mcf, significant operating costs associated with non-producing properties in the dewatering stage have been excluded. For June 2005 (the first full month of gas sales on the Frenchman project) the average operating cost per Mcf sold from producing properties was $0.77.

19

Revenues and Sales Volumes

The 105% increase in our operating revenues was primarily due to significantly greater sales volumes from our Australian Comet Ridge project.  In 2004, Comet Ridge sales volumes were reduced due to decreased delivery requirements from Energex, our sole customer.

During the second quarter of 2005, we had increased United States revenue and volumes from commencing on May 22, 2005 gas sales in our Frenchman project in Colorado.

Costs and Expenses

Operating expenses in Australia for 2005 were higher principally due to gas transportation costs associated with a significant portion of our gas being transported approximately 90 miles from the field prior to sale.  During the second quarter of 2004, our gas was all sold at the field.  Operating expenses in Australia also increased due to increased gas compression and field activity costs associated with significantly greater gas sales volumes.  Australian oil and gas property DD&A increased by 95% primarily due to increased Comet Ridge sales volumes.

United States operating expenses in the second quarter of 2005 and 2004 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 second quarter of 2005 increased 16% compared to the second quarter ended June 30, 2004.  The anticipated decline in legal expenses due to the end of the Tri-Star litigation was offset by higher consulting costs associated with the sale of Slough’s interest in the Company to Santos and higher employee costs.

Other Income (Expense)

Interest expense increased by 12% as the reduced cost associated with lower interest rates obtained under the Australian bank debt were offset by increased loan balances.

20

Results of Operations - Comparison of the Six Months Ended June 30, 2005 and 2004

We incurred a net loss of approximately $7.6 million for the six months ended June 30, 2005 compared to a net loss of approximately $8.0 million for the six months ended June 30, 2004.  The lower net loss for the six months ended June 30, 2005 was primarily due to higher gas revenues, partially offset by higher operating costs and depreciation, depletion and amortization.  The table below provides a comparison of operations for the six months ended June 30, 2005 with those of the prior year’s six months.  The table 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.  Certain prior period amounts may have been reclassified to ensure comparability.

	Six Months Ended June 30,				Increase			% Increase
	2005		2004		(Decrease)			(% Decrease)
	($ in thousands, except average per Mcf prices and costs)
Worldwide operations:
Gas revenue	$	6,574	$	2,730	$	3,844		141	%
Gas volumes (MMcf)	3,317		1,589		1,728			109	%
Average gas price per Mcf	$	1.98	$	1.72	$	0.26		15	%
Operating expenses	$	4,362	$	2,641	$	1,721		65	%
Average operating costs per Mcf sold	$	1.32	$	1.66	$	(0.34	)	(21	)%
General and administrative	$	3,937	$	3,554	$	383		11	%
Depreciation, depletion and amortization (“DD&A”)	$	1,370	$	607	$	763		126	%
Impairment of oil and gas properties	$	—	$	150	$	(150	)	(100	)%
Interest expense	$	4,519	$	4,233	$	286		7	%
Australia operations:
Gas revenue	$	6,366	$	2,726	$	3,640		134	%
Gas volumes (MMcf)	3,283		1,588		1,695			107	%
Average gas price per Mcf	$	1.94	$	1.72	$	0.22		13	%
Operating expenses	$	3,649	$	2,165	$	1,484		69	%
Average operating costs per Mcf sold	$	1.11	$	1.36	$	(0.25	)	(18	)%
Oil and Gas property DD&A	$	1,253	$	510	$	743		146	%
Other DD&A	$	66	$	69	$	(3	)	(4	)%
Oil and Gas DD&A rate per Mcf sold	$	0.38	$	0.32	$	0.06		19	%
United States operations:
Gas revenue	$	208	$	4	$	204		5,100	%
Gas volumes (MMcf)	34		1		33			3,300	%
Average gas price per Mcf	$	6.12	$	4.04	$	2.08		51	%
Operating expenses - producing properties	$	83	$	2	$	81		4,050	%
Average operating costs per Mcf sold(1)	$	2.44	$	2.29	$	.15		7	%
Operating expenses - non-producing properties	$	630	$	474	$	156		33	%
Impairment of oil and gas properties	$	—	$	150	$	(150	)	(100	)%
Oil and Gas property DD&A	$	20	$	—	$	20		N/A
Other DD&A	$	31	$	28	$	3		11	%

(1)Average operating costs per Mcf for the six months is for our producing properties.  To provide a more meaningful comparison of operating costs per Mcf, significant operating costs associated with non-producing properties in the dewatering stage have been excluded.. For June 2005 (the first full month of gas sales on the Frenchman project) the average operating cost per Mcf sold from producing properties was $0.77.

21

Revenues and Sales Volumes

The 141% increase in our operating revenues was primarily due to significantly greater sales volumes from our Australian Comet Ridge project.  In 2004, Comet Ridge sales volumes were reduced due to decreased delivery requirements from Energex, our sole customer.

During the first six months of 2005, we had increased United States revenue and volumes from commencing on May 22, 2005 gas sales in our Frenchman project in Colorado.

Costs and Expenses

Operating expenses in Australia for 2005 were higher principally due to gas transportation costs associated with a significant portion of our 2005 gas sales being transported approximately 90 miles from the field prior to sale.  During the first six months of 2004, our gas was all sold in the field.  Operating expenses in Australia also increased due to increased gas compression and field activity costs associated with significantly greater gas sales volumes.  Australian oil and gas property DD&A increased by 146% primarily due to increased Comet Ridge sales volumes.

United States operating expenses for the first six months of 2005 and 2004 are principally attributable to the Lay Creek coal-seam gas project where the wells are in the dewatering phase.

The impairment expense of $150,000 in 2004 was attributed to unsuccessful exploration costs incurred on wells on the Frenchman prospect.

General and administrative (“G&A”) expenses for the first six months of 2005 increased 11% compared to the first six months ended June 30, 2004.  The anticipated decline in legal expenses due to the end of the Tri-Star litigation was offset by higher consulting costs associated with the sale of slough’s interest in the Company to Santos and higher employee costs.

Other Income (Expense)

Interest expense increased by 7% as the reduced cost associated with lower interest rates obtained under the Australian bank debt were offset by increased loan balances.

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.  We do not use financial instruments to any degree to manage foreign currency, interest rate or commodity risk and do not hold or issue financial instruments to any degree for trading purposes. Our Australian debt facility and a portion of our debt payable to Slough have variable interest rates.  Fluctuations in the interest rate could increase or decrease our interest expense.  At June 30, 2005, we had approximately $105 million 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 $1.0 million.  In addition, at June 30, 2005, we were exposed to some market risk with respect to foreign currency and natural gas prices; however, management does not believe such risk to be material.

22

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.

23

PART II - OTHER INFORMATION

Item 1.    Legal Proceedings

No material proceedings.

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 6.    Exhibits

The following exhibits are filed herewith:

Numbers	Description
3.1	Restated Articles of Incorporation of Tipperary Corporation adopted May 6, 1993, originally filed as Exhibit 3.9 to Amendment No. 1 to Registration Statement on Form S-1 filed with the Commission on June 29, 1993, and incorporated herein by reference.
3.2	Restated Corporate Bylaws of Tipperary Corporation adopted June 28, 1993, originally filed as Exhibit 3.10 to Amendment No. 1 to Registration Statement on Form S-1 filed with the Commission on June 29, 1993, and incorporated herein by reference.
3.3	Articles of Amendment of the Articles of Incorporation of Tipperary Corporation adopted January 25, 2000, originally filed as Exhibit 3.11 to Form 10-QSB for the quarterly period ended December 31, 1999, and incorporated herein by reference.
4.1	Credit Facility Agreement dated March 21, 2003 for AUD$27.5 million between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077536871), the borrower, Tipperary Corporation, the Guarantor and Slough Trading Estate Limited, the lender, originally filed as Exhibit 4.77 to Form 10-Q for the quarterly period ended March 31, 2003, and incorporated herein by reference.
4.2	Credit Facility Agreement dated March 21, 2003 for U.S.$8.5 million between Tipperary Corporation, the borrower and Slough Trading Estate Limited, the lender, originally filed as Exhibit 4.78 to Form 10-Q for the quarterly period ended March 31, 2003, and incorporated herein by reference.
4.4	Promissory Note dated March 15, 2005, in the amount of $5.0 million issued by Tipperary Corporation to Slough Estates USA Inc., filed as Exhibit 4.4 to Form 10-K filed with the Commission on March 24, 2005, and incorporated herein by reference.
4.5	Letters of Variation dated November 25, 2003, July 2, 2004, August 3, 2004 and September 3, 2004, increasing the amount borrowed from Slough Trading Estate Limited from U.S. $8.5 million to U.S. $13.0 million related to the Credit Facility Agreement dated march 21, 2003, for U.S. $8.5 million, filed as Exhibit 4.5 to Form 10-K filed with the Commission on March 24, 2005, and incorporated herein by reference.
4.6	Comet Ridge Project Facilities Agreement and related agreements dated June 9, 2004, including the Comet Ridge Project TOGA/TCSG Deed of Security of which a portion on Page 59 of this agreement noted by “***” has been omitted pursuant to a request for confidential treatment, and such material has been filed separately with the Securities and Exchange Commission under Rule 246-2 of the Securities Exchange Act of 1934. Agreements originally filed as Exhibits 4.79(a), 4.79(b), 4.79(c), 4.79(d), 4.79(e), 4.79(f), 4.79(g) and 4.79(h) to Form 8-k filed with the Commission on June 30, 2004 and incorporated herein by reference.
4.7	Stock Purchase Agreement dated September 20, 2004, including the Registration Rights Agreement originally filed as Exhibit 4.79 to Form 8-K filed with the Commission on September 24, 2004 and incorporated herein by reference.

24

Numbers	Description
4.8	Promissory note for $9.4 million dated May 13, 2005 to Slough Estates USA Inc., filed as Exhibit 4.8 to Form 8-K on May 18, 2005, and incorporated herein by reference.
4.9	Promissory note for $11.4 million dated August 1, 2005 to Santos International Holdings Pty ltd, filed herewith.
10.1	Tipperary Corporation 1997 Long-Term Incentive Plan filed as Exhibit A to the Proxy Statement for its Annual Meeting of Shareholders held on January 28, 1997, originally filed as Exhibit 10.51 to Form 10-Q dated December 31, 1996, and incorporated herein by reference.
10.2	Warrant to Purchase common stock dated December 22, 1998, issued to Slough Estates USA Inc., originally filed as Exhibit 10.58 to Form 10-Q for the quarterly period ended December 31, 1998, and incorporated herein by reference.
10.3	Warrant to Purchase common stock dated December 23, 1999, issued to Slough Estates USA Inc., originally filed as Exhibit 10.60 to Form 10-QSB for the quarterly period ended December 31, 1999, and incorporated herein by reference.
10.4	Warrant to Purchase common stock dated February 9, 2000, issued to James H. Marshall, originally filed as Exhibit 10.70 to Form 10-QSB for the quarterly period ended March 31, 2000, and incorporated herein by reference.
10.5	Warrant to Purchase common stock dated February 9, 2000, issued to James F. Knott, originally filed as Exhibit 10.71 to Form 10-QSB for the quarterly period ended March 31, 2000, and incorporated herein by reference.
10.6	Gas Supply Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) and Energex Retail Pty Ltd (ACN 078 849 055) dated June 23, 2000. Confidential portions of this agreement noted by “***” have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidentiality under Rule 24b-2 of the Securities Exchange Act of 1934, originally filed as Exhibit 10.76 to Form 10-QSB for the quarterly period ended June 30, 2000, and incorporated herein by reference.
10.7	Warrant to Purchase common stock dated May 3, 2000, issued to Charles T. Maxwell, originally filed as Exhibit 10.77 to Form 10-KSB(A) for the transition period ended December 31, 2000, and incorporated herein by reference.
10.8	Warrant to Purchase common stock dated November 30, 2000, issued to D. Leroy Sample, originally filed as Exhibit 10.79 to Form 10-KSB(A) for the transition period ended December 31, 2000, and incorporated herein by reference.
10.9	Purchase and Sale Agreement dated May 4, 2001, by and between Tipperary Oil & Gas Corporation and Koch Exploration Company, originally filed as Exhibit 10.80 to Form S-3, SEC File No. 333-59052, filed with the Commission on July 26, 2001, and incorporated herein by reference.
10.10	Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated September 28, 2001. Confidential portions of this agreement noted by “***” have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidentiality under Rule 24b-2 of the Securities Exchange Act of 1934, originally filed as Exhibit 10.81 to Form 8-K filed with the Commission on October 18, 2001, and incorporated herein by reference.
10.11	Employment Agreement dated September 18, 2001 between Tipperary Corporation and David L. Bradshaw, originally filed as Exhibit 10.82 to Form 8-K filed with the Commission on October 18, 2001, and incorporated herein by reference.
10.12	Warrant to Purchase common stock dated January 30, 2002, issued to Jeff T. Obourn, originally filed as Exhibit 10.83 to Form 10-KSB for the year ended December 31, 2001, and incorporated herein by reference.

25

Numbers	Description
10.13	First Amendment to Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated May 30, 2002, originally filed as Exhibit 10.87 to Form 10-QSB for the quarterly period ended June 30, 2002, and incorporated herein by reference.
10.14	Second Amendment to Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated September 1, 2002, originally filed as Exhibit 10.88 to Form 10-QSB for the quarterly period ended September 30, 2002, and incorporated herein by reference.
10.15	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, originally filed as Exhibit 10.89 to Form 10-QSB for the quarterly period ended September 30, 2002, and incorporated herein by reference.
10.16	Purchase and Sale agreement dated November 27, 2002, between Tipperary Oil & Gas Corporation as Seller and Kerr-McGee Rocky Mountain Corporation as Buyer, originally filed as Exhibit 10.90 to Form 8-K filed with the Commission on December 12, 2002, and incorporated herein by reference.
10.17	Third Amendment to Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated January 1, 2003, originally filed as Exhibit 10.91 to Form 10-KSB for the year ended December 31, 2002, and incorporated herein by reference.
10.18	Gas Supply Term Sheet between Tipperary Oil & Gas (Australia) Pty Ltd (ABN 46 077 536 871) as Seller and Origin Energy Retail Limited (ABN 22 078 868 425) as Buyer, dated December 12, 2002. Confidential portions of this agreement noted by an “*” have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidentiality under Rule 24b-2 of the Securities Exchange Act of 1934, originally filed as Exhibit 10.92 to Form 10-KSB for the year ended December 31, 2002, and incorporated herein by reference.
10.19	Warrant to Purchase common stock dated February 3, 2003, issued to Jeff T. Obourn, originally filed as Exhibit 10.93 to Form 10-KSB for the year ended December 31, 2002, and incorporated herein by reference.
10.20	Warrant to Purchase common stock dated February 3, 2003, issued to David L. Bradshaw, originally filed as Exhibit 10.94 to Form 10-KSB for the year ended December 31, 2002, and incorporated herein by reference.
10.21	Warrant to Purchase common stock dated February 3, 2003, issued to Kenneth L. Ancell, originally filed as Exhibit 10.95 to Form 10-KSB for the year ended December 31, 2002, and incorporated herein by reference.
10.22	Employment Agreement dated October 17, 2002, between Tipperary Corporation and Kenneth L. Ancell, originally filed as Exhibit 10.96 to Form 10-KSB for the year ended December 31, 2002, and incorporated herein by reference.
10.23	Fourth Amendment to Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated March 31, 2003, originally filed as Exhibit 10.97 to Form 10-Q for the quarterly period ended June 30, 2003, and incorporated herein by reference.
10.24	Fifth Amendment to Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated June 30, 2003. Confidential portions of this agreement noted by an “*” have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidentiality under Rule 24b-2 of the Securities Exchange Act of 1934, originally filed as Exhibit 10.98 to Form 10-Q for the quarterly period ended September 30, 2003, and incorporated herein by reference.

26

Numbers	Description
10.25	Sixth Amendment to Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated December 31, 2003, originally filed as Exhibit 10.99 to Form 10-K for the year ended December 31, 2003, and incorporated herein by reference.
10.26	Seventh Amendment to Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated March 31, 2004, originally filed as Exhibit 10.98 to Form 10-Q for the quarterly period ended March 31, 2004, and incorporated herein by reference.
10.27	Settlement Agreement & Mutual Release dated October 30, 2004, between Tipperary Corporation and Tri-Star Petroleum, originally filed as Exhibit 10.101 to Form 8K filed with Commission on November 4, 2004, and incorporated herein by reference.
10.28	Eighth Amendment to Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated September 30, 2004, filed as Exhibit 10.28 to Form 10-K filed with the Commission on March 24, 2005 and incorporated herein by reference.
10.29	Extension to Gas Supply Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ABN 46 077 536 871) as Seller and Energex Retail Pty ltd (ABN 97 078 849 055) as Buyer, dated December 16, 2004, disclosed on Form 8-K filed with the Commission on December 23, 2004. Confidential portions of this agreement noted by an “***” have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidentiality under Rule 24b-2 of the Securities Exchange Act of 1934, filed as Exhibit 10.29 to Form 10-K filed with the Commission on March 24, 2005 and incorporated herein by reference.
10.30	Gas Supply Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ABN 46 077 536 871) as Seller and Orica Australia Pty Ltd (ABN 99 004 117 828) as Buyer, dated December 23, 2004, disclosed on Form 8-K filed with the Commission on December 23, 2004. Confidential portions of this agreement noted by an “***” have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidentiality under Rule 24b-2 of the Securities Exchange Act of 1934, filed as Exhibit 10.30 to Form 10-K filed with the Commission on March 24, 2005, and incorporated herein by reference.
10.31	Gas Supply Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ABN 46 077 536 871) as Seller and Santos QNT Pty Ltd (ABN 33 083 077 196) as Buyer, dated December 30, 2004, disclosed on Form 8-K filed with the Commission on January 4, 2005. Confidential portions of this agreement noted by an “***” have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidentiality under Rule 24b-2 of the Securities Exchange Act of 1934, filed as Exhibit 10.31 to Form 10-K filed with the Commission on March 24, 2005, and incorporated herein by reference.
10.32	Extension to Employment Agreement, between Tipperary Corporation and Jeff T. Obourn, dated January 6, 2005 and related Employment Agreement dated January 17, 2002, disclosed on Form 8-K filed with the Commission on January 12, 2005, filed as Exhibit 10.32 to Form 10-K filed with the Commission on March 24, 2005, and incorporated herein by reference.
10.33	Financial Advisory and Investment Banking Services Agreement between Tipperary Corporation and Houlihan Lokey Howard & Zukin Capital, Inc., dated February 22, 2005, disclosed on Form 8-K filed with the Commission on February 25, 2005, filed as Exhibit 10.33 to Form 10-K filed with the Commission on March 24, 2005, and incorporated herein by reference.
10.34	Ninth Amendment to Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated December 31, 2004, filed as Exhibit 10.34 to Form 10-K filed with the Commission on March 24, 2005, and incorporated herein by reference.

27

Numbers	Description
10.35	Warrants to purchase common stock dated January 10, 2005 and approved April 26, 2005 and disclosed in Current Report on 8-K filed on April 29, 2005. Warrants issued to Kenneth L. Ancell, David L. Bradshaw, Jeff T. Obourn, Eugene I. Davis, Douglas Kramer, Charles T. Maxwell and D. Leroy Sample and filed as Exhibit 10.35 to Form 10-Q filed with the Commission on May 16, 2005, and incorporated herein by reference.
10.36	Change in control severance agreements approved April 25, 2005 and disclosed in Current Report on 8-K filed on April 29, 2005. Agreements with David L. Bradshaw, Kenneth L. Ancell, Jeff T. Obourn and Joseph Feiten and filed as Exhibit 10.36 to Form 10-Q filed with the Commission on May 16, 2005, and incorporated herein by reference.
10.37	Agreement and Plan of Merger between Tipperary Corporation and Santos International Holdings Pty Ltd and Santos Acquisition Co. and filed as Exhibit 10.37 to Form 8-K on July 8, 2005.
10.38	Amended and Restated Agreement and Plan of Merger between Tipperary Corporation and Santos International Holding Pty Ltd and Santos Acquisition Co and filed as Exhibit 10.38 to Form 8-K on July 8, 2005.
10.39	Amended Change in Control Severance Agreements approved June 3, 2005 and disclosed in Current Report on Form 8-K filed on June 9, 2005. Agreements with David L. Bradshaw, Kenneth L. Ancell, Jeff T. Obourn and Joseph Feiten and 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.

28

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

			Tipperary Corporation
			Registrant
Date:	August 15, 2005	By:	/s/ David L. Bradshaw
			David L. Bradshaw, President, Chief Executive Officer
			and Chairman of the Board of Directors
Date:	August 15, 2005	By:	/s/ Joseph B. Feiten
			Joseph B. Feiten, Chief Financial Officer and
			Principal Accounting Officer

29

EXHIBIT INDEX

Numbers	Description
3.1	Restated Articles of Incorporation of Tipperary Corporation adopted May 6, 1993, originally filed as Exhibit 3.9 to Amendment No. 1 to Registration Statement on Form S-1 filed with the Commission on June 29, 1993, and incorporated herein by reference.
3.2	Restated Corporate Bylaws of Tipperary Corporation adopted June 28, 1993, originally filed as Exhibit 3.10 to Amendment No. 1 to Registration Statement on Form S-1 filed with the Commission on June 29, 1993, and incorporated herein by reference.
3.3	Articles of Amendment of the Articles of Incorporation of Tipperary Corporation adopted January 25, 2000, originally filed as Exhibit 3.11 to Form 10-QSB for the quarterly period ended December 31, 1999, and incorporated herein by reference.
4.1	Credit Facility Agreement dated March 21, 2003 for AUD$27.5 million between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077536871), the borrower, Tipperary Corporation, the Guarantor and Slough Trading Estate Limited, the lender, originally filed as Exhibit 4.77 to Form 10-Q for the quarterly period ended March 31, 2003, and incorporated herein by reference.
4.2	Credit Facility Agreement dated March 21, 2003 for U.S.$8.5 million between Tipperary Corporation, the borrower and Slough Trading Estate Limited, the lender, originally filed as Exhibit 4.78 to Form 10-Q for the quarterly period ended March 31, 2003, and incorporated herein by reference.
4.4	Promissory Note dated March 15, 2005, in the amount of $5.0 million issued by Tipperary Corporation to Slough Estates USA Inc., filed as Exhibit 4.4 to Form 10-K filed with the Commission on March 24, 2005, and incorporated herein by reference.
4.5	Letters of Variation dated November 25, 2003, July 2, 2004, August 3, 2004 and September 3, 2004, increasing the amount borrowed from Slough Trading Estate Limited from U.S. $8.5 million to U.S. $13.0 million related to the Credit Facility Agreement dated march 21, 2003, for U.S. $8.5 million, filed as Exhibit 4.5 to Form 10-K filed with the Commission on March 24, 2005, and incorporated herein by reference.
4.6	Comet Ridge Project Facilities Agreement and related agreements dated June 9, 2004, including the Comet Ridge Project TOGA/TCSG Deed of Security of which a portion on Page 59 of this agreement noted by “***” has been omitted pursuant to a request for confidential treatment, and such material has been filed separately with the Securities and Exchange Commission under Rule 246-2 of the Securities Exchange Act of 1934. Agreements originally filed as Exhibits 4.79(a), 4.79(b), 4.79(c), 4.79(d), 4.79(e), 4.79(f), 4.79(g) and 4.79(h) to Form 8-k filed with the Commission on June 30, 2004 and incorporated herein by reference.
4.7	Stock Purchase Agreement dated September 20, 2004, including the Registration Rights Agreement originally filed as Exhibit 4.79 to Form 8-K filed with the Commission on September 24, 2004 and incorporated herein by reference.
4.8	Promissory note for $9.4 million dated May 13, 2005 to Slough Estates USA Inc., filed as Exhibit 4.8 to Form 8-K on May 18, 2005, and incorporated herein by reference.
4.9	Promissory note for $11.4 million dated August 1, 2005 to Santos International Holdings Pty ltd, filed herewith.
10.1	Tipperary Corporation 1997 Long-Term Incentive Plan filed as Exhibit A to the Proxy Statement for its Annual Meeting of Shareholders held on January 28, 1997, originally filed as Exhibit 10.51 to Form 10-Q dated December 31, 1996, and incorporated herein by reference.
10.2	Warrant to Purchase common stock dated December 22, 1998, issued to Slough Estates USA Inc., originally filed as Exhibit 10.58 to Form 10-Q for the quarterly period ended December 31, 1998, and incorporated herein by reference.

30

Numbers	Description
10.3	Warrant to Purchase common stock dated December 23, 1999, issued to Slough Estates USA Inc., originally filed as Exhibit 10.60 to Form 10-QSB for the quarterly period ended December 31, 1999, and incorporated herein by reference.
10.4	Warrant to Purchase common stock dated February 9, 2000, issued to James H. Marshall, originally filed as Exhibit 10.70 to Form 10-QSB for the quarterly period ended March 31, 2000, and incorporated herein by reference.
10.5	Warrant to Purchase common stock dated February 9, 2000, issued to James F. Knott, originally filed as Exhibit 10.71 to Form 10-QSB for the quarterly period ended March 31, 2000, and incorporated herein by reference.
10.6	Gas Supply Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) and Energex Retail Pty Ltd (ACN 078 849 055) dated June 23, 2000. Confidential portions of this agreement noted by “***” have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidentiality under Rule 24b-2 of the Securities Exchange Act of 1934, originally filed as Exhibit 10.76 to Form 10-QSB for the quarterly period ended June 30, 2000, and incorporated herein by reference.
10.7	Warrant to Purchase common stock dated May 3, 2000, issued to Charles T. Maxwell, originally filed as Exhibit 10.77 to Form 10-KSB(A) for the transition period ended December 31, 2000, and incorporated herein by reference.
10.8	Warrant to Purchase common stock dated November 30, 2000, issued to D. Leroy Sample, originally filed as Exhibit 10.79 to Form 10-KSB(A) for the transition period ended December 31, 2000, and incorporated herein by reference.
10.9	Purchase and Sale Agreement dated May 4, 2001, by and between Tipperary Oil & Gas Corporation and Koch Exploration Company, originally filed as Exhibit 10.80 to Form S-3, SEC File No. 333-59052, filed with the Commission on July 26, 2001, and incorporated herein by reference.
10.10	Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated September 28, 2001. Confidential portions of this agreement noted by “***” have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidentiality under Rule 24b-2 of the Securities Exchange Act of 1934, originally filed as Exhibit 10.81 to Form 8-K filed with the Commission on October 18, 2001, and incorporated herein by reference.
10.11	Employment Agreement dated September 18, 2001 between Tipperary Corporation and David L. Bradshaw, originally filed as Exhibit 10.82 to Form 8-K filed with the Commission on October 18, 2001, and incorporated herein by reference.
10.12	Warrant to Purchase common stock dated January 30, 2002, issued to Jeff T. Obourn, originally filed as Exhibit 10.83 to Form 10-KSB for the year ended December 31, 2001, and incorporated herein by reference.
10.13	First Amendment to Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated May 30, 2002, originally filed as Exhibit 10.87 to Form 10-QSB for the quarterly period ended June 30, 2002, and incorporated herein by reference.
10.14	Second Amendment to Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated September 1, 2002, originally filed as Exhibit 10.88 to Form 10-QSB for the quarterly period ended September 30, 2002, and incorporated herein by reference.

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Numbers	Description
10.15	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, originally filed as Exhibit 10.89 to Form 10-QSB for the quarterly period ended September 30, 2002, and incorporated herein by reference.
10.16	Purchase and Sale agreement dated November 27, 2002, between Tipperary Oil & Gas Corporation as Seller and Kerr-McGee Rocky Mountain Corporation as Buyer, originally filed as Exhibit 10.90 to Form 8-K filed with the Commission on December 12, 2002, and incorporated herein by reference.
10.17	Third Amendment to Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated January 1, 2003, originally filed as Exhibit 10.91 to Form 10-KSB for the year ended December 31, 2002, and incorporated herein by reference.
10.18	Gas Supply Term Sheet between Tipperary Oil & Gas (Australia) Pty Ltd (ABN 46 077 536 871) as Seller and Origin Energy Retail Limited (ABN 22 078 868 425) as Buyer, dated December 12, 2002. Confidential portions of this agreement noted by an “*” have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidentiality under Rule 24b-2 of the Securities Exchange Act of 1934, originally filed as Exhibit 10.92 to Form 10-KSB for the year ended December 31, 2002, and incorporated herein by reference.
10.19	Warrant to Purchase common stock dated February 3, 2003, issued to Jeff T. Obourn, originally filed as Exhibit 10.93 to Form 10-KSB for the year ended December 31, 2002, and incorporated herein by reference.
10.20	Warrant to Purchase common stock dated February 3, 2003, issued to David L. Bradshaw, originally filed as Exhibit 10.94 to Form 10-KSB for the year ended December 31, 2002, and incorporated herein by reference.
10.21	Warrant to Purchase common stock dated February 3, 2003, issued to Kenneth L. Ancell, originally filed as Exhibit 10.95 to Form 10-KSB for the year ended December 31, 2002, and incorporated herein by reference.
10.22	Employment Agreement dated October 17, 2002, between Tipperary Corporation and Kenneth L. Ancell, originally filed as Exhibit 10.96 to Form 10-KSB for the year ended December 31, 2002, and incorporated herein by reference.
10.23	Fourth Amendment to Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated March 31, 2003, originally filed as Exhibit 10.97 to Form 10-Q for the quarterly period ended June 30, 2003, and incorporated herein by reference.
10.24	Fifth Amendment to Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated June 30, 2003. Confidential portions of this agreement noted by an “*” have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidentiality under Rule 24b-2 of the Securities Exchange Act of 1934, originally filed as Exhibit 10.98 to Form 10-Q for the quarterly period ended September 30, 2003, and incorporated herein by reference.
10.25	Sixth Amendment to Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated December 31, 2003, originally filed as Exhibit 10.99 to Form 10-K for the year ended December 31, 2003, and incorporated herein by reference.
10.26	Seventh Amendment to Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated March 31, 2004, originally filed as Exhibit 10.98 to Form 10-Q for the quarterly period ended March 31, 2004, and incorporated herein by reference.

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Numbers	Description
10.27	Settlement Agreement & Mutual Release dated October 30, 2004, between Tipperary Corporation and Tri-Star Petroleum, originally filed as Exhibit 10.101 to Form 8K filed with Commission on November 4, 2004, and incorporated herein by reference.
10.28	Eighth Amendment to Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated September 30, 2004, filed as Exhibit 10.28 to Form 10-K filed with the Commission on March 24, 2005 and incorporated herein by reference.
10.29	Extension to Gas Supply Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ABN 46 077 536 871) as Seller and Energex Retail Pty ltd (ABN 97 078 849 055) as Buyer, dated December 16, 2004, disclosed on Form 8-K filed with the Commission on December 23, 2004. Confidential portions of this agreement noted by an “***” have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidentiality under Rule 24b-2 of the Securities Exchange Act of 1934, filed as Exhibit 10.29 to Form 10-K filed with the Commission on March 24, 2005 and incorporated herein by reference.
10.30	Gas Supply Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ABN 46 077 536 871) as Seller and Orica Australia Pty Ltd (ABN 99 004 117 828) as Buyer, dated December 23, 2004, disclosed on Form 8-K filed with the Commission on December 23, 2004. Confidential portions of this agreement noted by an “***” have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidentiality under Rule 24b-2 of the Securities Exchange Act of 1934, filed as Exhibit 10.30 to Form 10-K filed with the Commission on March 24, 2005, and incorporated herein by reference.
10.31	Gas Supply Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ABN 46 077 536 871) as Seller and Santos QNT Pty Ltd (ABN 33 083 077 196) as Buyer, dated December 30, 2004, disclosed on Form 8-K filed with the Commission on January 4, 2005. Confidential portions of this agreement noted by an “***” have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidentiality under Rule 24b-2 of the Securities Exchange Act of 1934, filed as Exhibit 10.31 to Form 10-K filed with the Commission on March 24, 2005, and incorporated herein by reference.
10.32	Extension to Employment Agreement, between Tipperary Corporation and Jeff T. Obourn, dated January 6, 2005 and related Employment Agreement dated January 17, 2002, disclosed on Form 8-K filed with the Commission on January 12, 2005, filed as Exhibit 10.32 to Form 10-K filed with the Commission on March 24, 2005, and incorporated herein by reference.
10.33	Financial Advisory and Investment Banking Services Agreement between Tipperary Corporation and Houlihan Lokey Howard & Zukin Capital, Inc., dated February 22, 2005, disclosed on Form 8-K filed with the Commission on February 25, 2005, filed as Exhibit 10.33 to Form 10-K filed with the Commission on March 24, 2005, and incorporated herein by reference.
10.34	Ninth Amendment to Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated December 31, 2004, filed as Exhibit 10.34 to Form 10-K filed with the Commission on March 24, 2005, and incorporated herein by reference.
10.35	Warrants to purchase common stock dated January 10, 2005 and approved April 26, 2005 and disclosed in Current Report on 8-K filed on April 29, 2005. Warrants issued to Kenneth L. Ancell, David L. Bradshaw, Jeff T. Obourn, Eugene I. Davis, Douglas Kramer, Charles T. Maxwell and D. Leroy Sample and filed as Exhibit 10.35 to Form 10-Q filed with the Commission on May 16, 2005, and incorporated herein by reference.
10.36	Change in control severance agreements approved April 25, 2005 and disclosed in Current Report on 8-K filed on April 29, 2005. Agreements with David L. Bradshaw, Kenneth L. Ancell, Jeff T. Obourn and Joseph Feiten and filed as Exhibit 10.36 to Form 10-Q filed with the Commission on May 16, 2005, and incorporated herein by reference.

33

Numbers	Description
10.37	Agreement and Plan of Merger between Tipperary Corporation and Santos International Holdings Pty Ltd and Santos Acquisition Co. and filed as Exhibit 10.37 to Form 8-K on July 8, 2005.
10.38	Amended and Restated Agreement and Plan of Merger between Tipperary Corporation and Santos International Holding Pty Ltd and Santos Acquisition Co and filed as Exhibit 10.38 to Form 8-K on July 8, 2005.
10.39	Amended Change in Control Severance Agreements approved June 3, 2005 and disclosed in Current Report on Form 8-K filed on June 9, 2005. Agreements with David L. Bradshaw, Kenneth L. Ancell, Jeff T. Obourn and Joseph Feiten and 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.

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