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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

Commission File Number 1-7796

TIPPERARY CORPORATION

(Exact name of registrant as specified in its charter)

(303) 293-9379

(Issuer’s telephone number)

Check whether the issuer (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act of 1934 during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes             ü             No                            

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

Yes                             No             ü            

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

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TIPPERARY CORPORATION AND SUBSIDIARIES

Index to Form 10-Q

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

TIPPERARY CORPORATION AND SUBSIDIARIES

Consolidated Balance Sheets

(in thousands)

(unaudited)

See accompanying notes to consolidated financial statements.

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TIPPERARY CORPORATION AND SUBSIDIARIES

Consolidated Statements of Operations

(in thousands, except per share data)

(unaudited)

See accompanying notes to consolidated financial statements.

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TIPPERARY CORPORATION AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(in thousands)

(unaudited)

See accompanying notes to consolidated financial statements.

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TIPPERARY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

In the opinion of management, the accompanying unaudited consolidated financial statements reflect all adjustments, consisting only of normal recurring adjustments, which are necessary for a fair presentation of the financial position of Tipperary Corporation and its subsidiaries (the “Company”) at March 31, 2003, and the results of its operations for the three-month periods ended March 31, 2003 and 2002 and its cash flows for the three-month periods ended March 31, 2003 and 2002. The consolidated financial statements include the accounts of Tipperary Corporation and its wholly-owned subsidiaries, Tipperary Oil and Gas Corporation and Burro Pipeline Corporation, and its 90%-owned subsidiary, Tipperary Oil and Gas (Australia) Pty Ltd (“TOGA”). All intercompany balances have been eliminated. The accounting policies followed by the Company are included in Note 1 to the Consolidated Financial Statements in its Annual Report on Form 10-KSB for the year ended December 31, 2002. These financial statements should be read in conjunction with the Form 10-KSB.

Impact of New Accounting Pronouncements

In June 2001, the FASB issued SFAS 143, “Accounting for Asset Retirement Obligations,” which provides accounting requirements for retirement obligations associated with tangible long-lived assets, including the timing of liability recognition, initial measurement of the liability, allocation of asset retirement costs to expense, subsequent measurement of the liability, and financial statement disclosures. SFAS 143 requires that asset retirement costs be capitalized along with the cost of the related long-lived asset. The asset retirement costs should then be allocated to expense using a systematic and rational method. The Company has determined that it has asset retirement costs associated with wells drilled in Australia and the United States. The Company also expects to incur retirement costs to dismantle two gas compression plant facilities located in Australia. The Company adopted SFAS 143 on January 1, 2003, which resulted in an increase in property, plant and equipment of $134,000 and establishment of an asset retirement obligation of $180,000. The transition adjustment of $46,000 was reported as a cumulative effect of accounting change. As of January 1, 2002, the Company’s asset retirement obligation was $145,000. The Company’s pro forma net loss would have been $1,588,000 for the three months ended March 31, 2002 assuming SFAS 143 had been adopted on January 1, 2002. As a result of adopting SFAS 143, the estimated asset retirement obligation accretion for 2003 is expected to be approximately $23,000.

Stock-Based Compensation

Statements of Financial Accounting Standards Nos. 148 and No. 123 encourage, but do not require, companies to record the compensation cost for stock-based employee compensation plans at fair value. At March 31, 2003, the Company had two stock-based employee option plans and warrants issued to Directors, Employees and Non-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 123 and 148. Accordingly, compensation cost for fixed stock options and warrants is measured as the excess, if any, of the quoted market price of the Company’s stock at the date of the grant over the amount an employee must pay to acquire the stock. Pro forma disclosures as if the Company had adopted the cost recognition provisions of SFAS 148 and 123 are presented below.

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Disposition of Oil and Gas Properties

Under the full cost method of accounting for oil and gas exploration and production, sales of oil and gas properties are accounted for as adjustments of capitalized costs, with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. If a gain or loss is to be recognized, the cost of the property sold is an allocation of the cost center’s total costs based on the relative fair market value of the property sold compared to the estimated fair market value of the properties retained when there are substantial economic differences between the property sold and the properties retained.

Gas Imbalances

In natural gas production operations, joint owners sometimes sell more or less than the production volumes to which they are entitled based on their revenue ownership interest. The joint operating agreement includes gas balancing provisions to govern production allocations in this situation. The Company records a natural gas imbalance in other liabilities if any excess takes of natural gas exceed its remaining proved reserves for the property. As of March 31, 2003, 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 1,283,000 Mcf. Based on the average price of $1.32 per Mcf received during 2003 from these sales, this represents $1,694,000 in gas revenues. No liability has been recorded for the excess volumes taken as they do not exceed the Company’s share of remaining proved reserves. Under the terms of the gas balancing agreement, the Company may be required to reduce the monthly volumes it sells by up to 50% of its entitled share of sales, to enable underproduced parties to sell more than their entitled share of the gas sales and cure the imbalance. Any reduction in monthly volumes will negatively affect the Company’s revenues, and operating expenses will not decline proportionately.

Liquidity and Operations

The Company anticipates funding operations and domestic and Australian non-discretionary exploratory capital expenditures for the remainder of 2003 using (a) net gas revenues and (b) $25 million in long-term borrowings from Slough Trading Estates Limited (“STEL”), a UK company and wholly-owned subsidiary of Slough Estates plc and parent of Slough Estates USA Inc. (“Slough”), which owns 61.3% of the Company’s outstanding common stock. See Note 2 to the Consolidated Financial Statements.

In order to fund discretionary capital expenditures in 2003 in excess of these cash resources and to fund capital expenditures beyond 2003, the Company contemplates that it will require alternative sources of capital. Potential additional sources of funding are expected to include additional debt financings and asset sales. The Company is currently in formal discussions with a group of banks interested in providing debt financing to TOGA. The Company is seeking the financing to be (a) available in the third quarter of 2003, (b) secured by the Company’s consolidated interests in the Comet Ridge project in Queensland, Australia, and (c) partially guaranteed by Slough Estates plc, STEL’s UK parent. If obtained, the Company anticipates that the financing would be used to repay the Company’s existing long-term debt with TCW Asset Management Company (“TCW”), repurchase an overriding royalty granted to TCW under the Company’s

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debt to TCW, and (to the extent available) fund Comet Ridge development in 2003, 2004 and early 2005.

On an ongoing basis, the Company seeks to sell its interests in its prospective acreage in the United States and retain carried working interests. In the event of such sales, the Company generates cash to reduce its investment in individual projects and fund exploration costs. However, in the event that sufficient capital cannot be generated from property sales or other funding cannot be obtained, the Company will be required to curtail planned expenditures and may have to sell additional acreage and/or relinquish acreage at prices that are not favorable to the Company.

NOTE 2 - RELATED PARTY TRANSACTIONS

In March 2003, the Company entered into two credit facility agreements with STEL allowing the Company to borrow on an unsecured basis up to $25 million from STEL. Interest is 13% per annum, payable quarterly and the loans mature on April 2, 2012. The Company may repay the loans in whole or in part without prepayment penalties. STEL may demand repayment prior to the maturity date provided that STEL gives 18-month notice following TCW approval or the Company’s repayment of its $22 million outstanding loan from TCW. The Company may continue to borrow under the STEL credit facilities during the 18-month notice period. Approximately two-thirds of the $25 million will be available to TOGA directly and in Australian dollars. Borrowings by TOGA may be used for exploration, development, and production costs of the Comet Ridge project as well as TOGA’s general and administrative costs and interest expense. Other Company borrowings may be used for general corporate purposes.

At March 31, 2003, the Company owed Slough $10,490,000 under two lending agreements. The first obligation, a loan for a drilling rig, is evidenced by a note payable with a balance of $1,790,000 at March 31, 2003. Principal payments on the rig loan are due monthly from rents received from the drilling contractor during the month. However, there are no mandatory principal payments prior to the maturity date. The loan bears interest at a rate of 10% per annum payable monthly and the note matures on July 31, 2004. The Company has also borrowed $4 million from Slough which is due on April 30, 2004, and is evidenced by a second note payable and bears an interest rate of LIBOR plus 3.5% (4.84% as of March 31, 2003). Additionally, the Company borrowed $4.7 million on a short-term basis from Slough during the first quarter of 2003 under the same terms as the $4 million Slough note payable. In April 2003, the Company used $4.7 million of the $25 million credit facility entered into with STEL in March 2003 to retire this short-term debt.

NOTE 3 - LONG-TERM DEBT - UNRELATED PARTY

The Company has an amended and restated Credit Agreement with TCW. As of March 31, 2003, the principal balance was $22 million, which was used for development of the Comet Ridge project. The loan is evidenced by senior secured promissory notes bearing interest at the rate of 10% per annum and payable quarterly. The Company must also make monthly payments to TCW equal to a 6% overriding royalty on the Company’s Comet Ridge gas sales revenues before deducting other costs and royalties.

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

Principal payments under the TCW loan are due quarterly beginning in March 2005 equal to 5.3875% of the unpaid principal balance, increasing to 6.59% in March 2006, decreasing to 5.91% in March 2007 and increasing to 7.09% in March 2008. The outstanding principal balance is due in full on December 31, 2008. The amended Credit Agreement has customary default provisions, including the failure to make required principal payments, under which TCW may require all obligations to be immediately due and payable. The amended Credit Agreement requires that TOGA maintain working capital of at least $500,000. As of March 31, 2003, the Company had met all debt covenants under the Credit Agreement with TCW.

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Upon receipt of the initial funding, the Company recorded deferred financing costs of approximately $6,800,000, which was the then present value (discounted at 15%) of the overriding royalty conveyed to TCW. This cost reduced the book value of oil and gas properties in Australia and is being amortized as interest expense over the life of the loan. Deferred loan costs also include approximately $1,683,000 of other costs incurred to obtain the TCW financing, which are likewise being amortized as interest expense over the life of the loan.

The Company is seeking to retire the $22 million TCW debt with alternative financing. In the event the $22 million TCW debt is repaid, the Company expects to purchase the 6% TCW overriding royalty. If the Company retires the TCW debt, any remaining TCW deferred loan costs currently being amortized will be expensed in full as a charge to operations in the period in which the debt is retired. As of March 31, 2003, these deferred loan costs totaled approximately $5.4 million.

NOTE 4—EARNINGS (LOSS) PER SHARE

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

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NOTE 5—COMMITMENTS AND CONTINGENCIES

The Company, TOGA and two unaffiliated working interest owners are plaintiffs in a lawsuit filed in 1998, styled Tipperary Corporation and Tipperary Oil & Gas (Australia) Pty Ltd v. Tri-Star Petroleum Company, James H. Butler, Sr., and James H. Butler, Jr., Cause No. CV42,265, District Court of Midland County, Texas involving the Comet Ridge project. The plaintiffs allege, among other matters, that Tri-Star and/or the individual defendants failed to operate the project in a good and workmanlike manner and committed various other breaches of a joint operating contract, breached a previous mediation agreement, committed certain breaches of fiduciary and other duties owed to the plaintiffs, and committed fraud in connection with the project. Tri-Star answered the allegations, and filed a counterclaim alleging tortious interference with respect to the contracts, the authority to prospect covering the project and contractual relationships with vendors; commercial disparagement; foreclosure of operator’s lien and alternatively forfeiture of undeveloped acreage; unjust enrichment and declaratory relief. As of February 2001, the District Court enjoined Tri-Star from asserting any forfeiture claims based upon events prior to that date. In March 2002, the court entered its Writ of Temporary Injunction (the “Injunction”) to enforce the votes of a majority-in-interest of the parties under the joint operating agreement to remove Tri-Star as operator and replace it with TOGA, which occurred on March 22, 2002. Tri-Star appealed the Injunction to the Texas Eighth District Court of Appeals. On January 31, 2003, the appellate court affirmed the action of the District Court in issuing the Injunction. Tri-Star has filed a Petition for Review in the Supreme Court of Texas. Review by the Texas Supreme Court is discretionary, and that Court has not yet decided whether it will hear the appeal. Absent a successful appeal to the Supreme Court of Texas by Tri-Star, TOGA will continue as operator of the Comet Ridge Project at least through the conclusion of a trial on the merits, and thereafter if successful at trial.

In June 2002, the District Court ruled as unenforceable the arbitration provisions of the existing mediation agreement between the parties and the obligation of the parties to arbitrate audit disputes. The District Court refused to refer any issues between the parties to arbitration. On July 10, 2002, Tri-Star filed a Notice of Accelerated Appeal of the order in the Texas Eighth District Court of Appeals. All briefing has been completed, oral argument took place in January of 2003, and a decision is expected within the next few months. Although pre-trial discovery is proceeding, the pending appeals delay the trial on the merits, and a new trial date will not be set before all appellate proceedings are resolved.

In January of 2003, the Company filed a Motion to Compel Compliance with Amended Writ of Temporary Injunction in the Midland County District Court. The Company has asked the District Court to compel Tri-Star to assign title in the Comet Ridge petroleum leases and ATPs to TOGA, in proportion to TOGA’s working interest, arguing that without such title TOGA, as operator, cannot control all aspects of the project as contemplated by the joint operating agreement and the Injunction. That motion is set for hearing beginning August 13, 2003.

The Company has made payments totaling approximately $1.2 million into the registry of the District Court for disputed portions of joint interest billings from Tri-Star. At the appropriate time, the District Court will determine the disposition of the funds paid into its registry. If the June 21, 2002 ruling on arbitration issues is upheld by the Court of Appeals, it is anticipated that the District Court will, at some point, return the funds to the Company. If all of the funds are returned, the Company will reduce its full cost pool for approximately $1 million of recovered capital costs and will record a gain of approximately $200,000 for recovered operating costs. If, and to the extent, such funds are awarded to Tri-Star, the Company will not record any additional expense.

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

TOGA, as operator of the Comet Ridge project, has requested that Tri-Star repay to other working interest owners $1.3 million of unapplied prepaid drilling costs. The Company’s share is $940,000 as of March 31, 2003, and the Company has recorded a fully reserved receivable, with no gain recognizable until the receivable is paid or payment is reasonably certain.

The Company may be entitled to additional damages based upon Tri-Star’s billing practices and handling of the arbitration process if the June 21, 2002 ruling of the District Court is upheld on final appeal.

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NOTE 6—OPERATIONS BY GEOGRAPHIC AREA

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

NOTE 7– PROPERTY, PLANT AND EQUIPMENT

A summary of property, plant and equipment follows:

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Item 2. Management’s Discussion and Analysis

Information within this report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are based on management’s beliefs, assumptions, current expectations, estimates and projections about the oil and gas industry, the world economy and about the Company itself. Words such as “may,” “will,” “expect,” “anticipate,” “estimate” or “continue,” or comparable words are intended to identify such forward-looking statements. In addition, all statements other than statements of historical facts that address activities that the Company expects or anticipates will or may occur in the future are forward-looking statements. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict with regard to timing, extent, likelihood and degree of occurrence. Therefore, actual results and outcomes may materially differ from what may be expressed or forecasted in such forward-looking statements. Furthermore, the Company undertakes no obligation to update, amend or clarify forward-looking statements, whether as a result of new information, future events or otherwise. Readers are encouraged to read the SEC filings of the Company, particularly its Form 10-KSB for the year ended December 31, 2002, for meaningful cautionary language disclosing why actual results may vary materially from those anticipated by management.

Overview

Australia

The Company’s activities in Australia are conducted substantially through Tipperary Corporation’s 90%-owned Australian subsidiary, Tipperary Oil & Gas (Australia) Pty Ltd (“TOGA”). As of March 31, 2003, the Company owned a total of 73% in undivided capital bearing interest in the Comet Ridge project in Queensland, Australia. This project comprises approximately 1,058,000 acres in the Bowen Basin and includes five petroleum leases covering approximately 278,000 acres, Authority to Prospect (“ATP”) 526 covering approximately 687,000 acres, and ATP 653 covering approximately 93,000 acres.

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

During 2003, ATP 526 and 653 have expenditure requirements totaling approximately $7.4 million net to the Company’s interest. The Company expects to meet these requirements by conducting seismic operations and exploratory drilling. ATP 526 and 653 have initial terms expiring on October 31, 2004 and September 30, 2006, respectively.

The table below summarizes field development progress on the Comet Ridge project. At May 1, 2003, the Company was completing the installation of a second compression plant facility. Upon completion of the facility, the Company may add approximately 3 MMcf per day to gross sales volumes through production of ten wells that have recently been connected to the gathering system. Additional sales are dependent upon the project’s gas purchasers making requests to purchase more gas volumes under existing contracts and/or the Company entering into additional contracts to sell available gas volumes.

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Comet Ridge Operations Review:

The Company plans to drill approximately 30 development wells on the Comet Ridge project during 2003, and expects to fund its share of drilling costs with financing received under a $25 million borrowing facility entered into in March 2003 with Slough Trading Estate Limited, a United Kingdom company which is affiliated with the Company’s majority shareholder. See Note 2 to the Consolidated Financial Statements.

During the first quarter of 2003, the Company sold 100% of its gas in Australia under two contracts with ENERGEX Retail Pty Ltd (“ENERGEX”), an unaffiliated customer. The first contract has delivery requirements of up to approximately 5,500 Mcf of gas per day through December 2003. A second five-year contract, entered into with ENERGEX effective June 1, 2000, has delivery requirements of up to approximately 15,000 Mcf of gas per day. In December 2002, the Company entered into a gas sales agreement with Origin Energy Retail Limited (“OERL”), a subsidiary of Origin Energy Limited, to supply approximately 9 Bcf per year, or around 25,000 Mcf of gas per day net to the Company’s interests, for thirteen years beginning May 2007. Effective March 31, 2003, the Company and Queensland Fertilizer Assets Limited (“QFAL”) extended until June 30, 2003 the Company’s gas sales agreement with QFAL to supply 260 Bcf of gas to QFAL over a 20-year period beginning in late 2005 to a fertilizer plant QFAL is planning to construct in southeastern Queensland. The Company believes it has reasonable certainty, based upon the gas market in Eastern Australia, that this production can be sold in the market, if not sold to QFAL.

Pursuant to litigation described in Note 5 to the Consolidated Financial Statements, TOGA became the operator of the Comet Ridge project during the fiscal year ended December 31, 2002.

In addition to the interest in the Comet Ridge project, TOGA holds a 100% interest in ATP’s 655 and 675 covering approximately 278,000 acres in total as of March 31, 2003. ATP’s 655 and 675 have initial terms expiring on October 31, 2003 and February 29, 2004, respectively. TOGA has drilled and completed a total of four exploratory wells on these ATPs, one of which is being tested and evaluated, and three of which were plugged and abandoned. As of March 31, 2003, TOGA had met all prior expenditure requirements on retained acreage. TOGA also holds a 25% interest in ATP 554, which covers approximately 111,000 acres.

During 2003, ATP 655 has expenditure requirements totaling approximately $960,000. The Company will continue to evaluate ATP 655 and 675 and will either meet the expenditure requirements or relinquish additional acreage based upon evaluation of data. On ATP 554 several conditions must be met by a third party before the Company can determine its commitment.

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United States

The Company holds a 50% working interest in and serves as operator of the Lay Creek coalseam gas project located in Moffat County, Colorado. The project includes various leasehold interests covering over 82,000 gross acres. Koch Exploration Company (“Koch”), an unaffiliated third party, holds the remaining 50% working interest under the terms of an agreement to conduct exploratory drilling over this area jointly. Koch paid the Company approximately $2 million for this interest at closing in May 2001 and agreed to pay the Company approximately $2 million for the Company’s share of costs to drill and complete wells on the project acreage. The Company drilled and completed two exploratory coalseam gas wells on this acreage during 2001 and completed a four-well pilot drilling program around one of the exploratory wells in early May 2002. During the third and fourth quarters of 2002, the Company drilled four additional exploratory coalseam gas wells offsetting the second exploratory well drilled in 2001 in the project. The Company is currently evaluating the gas and water production from these two five-well pilot programs in order to determine economic viability of the production.

In February 2002, the Company sold a 60% interest in the Nine Mile Prospect, a conventional oil and gas exploration prospect, which is also located in Moffat County, Colorado, to Elm Ridge Resources (“Elm Ridge”), an unaffiliated third party, for approximately $595,000. Elm Ridge also agreed to pay one-half of the Company’s share of drilling costs to an agreed casing point on the first well for its 40% retained interest. On September 17, 2002, the Company announced the completion and initial testing of the Tipperary Ninemile Federal 34-1 in the prospect. The Company and Elm Ridge subsequently drilled the Federal 3-1 well in the fourth quarter of 2002 to further test the productive formation. Elm Ridge served as operator of the project through March 25, 2003. The Company became operator of the Nine Mile prospect on March 26, 2003 after the resignation of the former operator. The Company plans to complete and test the Federal 3-1 in the second quarter of 2003. Based upon its geologic interpretation, the Company believes there may be potential for significant developmental drilling although there can be no such assurance. The Company will drill an additional well on the Nine Mile prospect in the second quarter of 2003 and may drill additional wells during 2003 depending on results of drilling. The project comprises approximately 49,000 gross acres. At December 31, 2002, the Company recognized natural gas equivalent proved reserves of approximately 2.3 billion cubic feet with respect to the Ninemile 34-1 well and associated offset locations, with a present value, discounted at 10%, of approximately $1.9 million.

In November 2002, the Company sold to Kerr-McGee Rocky Mountain Corporation (“Kerr-McGee’), an unaffiliated third party, interests ranging from 75% to 80% in the Frenchman and Republican prospects in eastern Colorado for $4,800,000 in cash. The Company retained the remaining 25% to 20% interests in the acreage. Total acreage in the project is approximately 280,000 gross acres. The Company and Kerr-McGee simultaneously entered into a joint operating agreement designating Kerr-McGee as operator, and have now completed initial seismic activities and are preparing to begin drilling. As a result of the sale, the Company recorded a $1,400,000 gain in the fourth quarter of 2002.

Financial Condition, Liquidity and Capital Resources

The Company had unrestricted cash and cash equivalents of $358,000 as of March 31, 2003, compared to $1,725,000 as of December 31, 2002. On April 2, 2003, the Company received $7.7 million in cash, drawing on the $25 million long-term, unsecured credit facilities described in Note 2 to the Consolidated Financial Statements. Working capital includes restricted cash of $187,000 as of March 31, 2003 and $546,000 as of December 31, 2002. Restricted cash consists of cash in collateral bank accounts maintained in connection with the TCW financing, the use of which is restricted to disbursements made either to TCW or as otherwise approved by TCW. The Company has funded operations and capital expenditures for the three months ended March 31, 2003, using primarily (a) $1.7 million of cash on hand at December 31, 2002 and (b) a $4.7 million short-term loan from Slough in February and March 2003 that was repaid on April 2, 2003 using a portion of the $7.7 million borrowings on the credit facilities.

The Company anticipates funding operations and domestic and Australian non-discretionary exploratory capital expenditures for the remainder of 2003 using (a) net gas revenues and (b) $25 million in long-term borrowings from Slough Trading Estates Limited (“STEL”), a UK company and wholly-owned subsidiary of Slough Estates plc and parent of Slough Estates USA Inc. (“Slough”), which owns 61.3% of the Company’s outstanding common stock. See Note 2 to the Consolidated Financial Statements.

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In order to fund discretionary capital expenditures in 2003 in excess of these cash resources and to fund capital expenditures beyond 2003, the Company contemplates that it will require alternative sources of capital. Potential additional sources of funding are expected to include additional debt financings and asset sales. The Company is currently in formal discussions with a group of banks interested in providing debt financing to TOGA. The Company is seeking the financing to be (a) available in the third quarter of 2003, (b) secured by the Company’s consolidated interests in the Comet Ridge project in Queensland, Australia, and (c) partially guaranteed by Slough Estates plc, STEL’s UK parent. If obtained, the Company anticipates that the financing would be used to repay the Company’s existing long-term debt with TCW Asset Management Company (“TCW”), repurchase an overriding royalty granted to TCW under the Company’s debt to TCW, and (to the extent available) fund Comet Ridge development in 2003, 2004 and early 2005.

On an ongoing basis, the Company seeks to sell its interests in its prospective acreage in the United States and retain carried working interests. In the event of such sales, the Company generates cash to reduce its investment in individual projects and fund exploration costs. However, in the event that sufficient capital cannot be generated from property sales or other funding cannot be obtained, the Company will be required to curtail planned expenditures and may have to sell additional acreage and/or relinquish acreage at prices that are not favorable to the Company.

Net cash used by operating activities was $1,741,000 during the three months ended March 31, 2003 compared to $1,277,000 of cash used during the same period last year. The need to use cash for operations in both periods resulted primarily from (a) interest expense on debt used to fund 2001 and 2002 property acquisition, exploration and development and (b) the sale of most of the Company’s U.S. oil and gas properties after June 30, 2000. However, the loss in revenues from domestic properties has been partially offset by steadily increasing sales of natural gas in Australia.

The table below provides a detailed analysis of capital expenditures of $4.55 million during the three months ended March 31, 2003.

Capital Expenditures Activity

(in thousands)

In January 2001, Slough advanced the Company $2,500,000 for the purchase of a drilling rig which the Company has leased to an unaffiliated drilling contractor in Australia. This loan bears interest at a fixed rate of 10% per annum and matures on July 31, 2004. Payments are due monthly equal to all rents the Company receives from the drilling contractor and for accrued interest on the balance of the loan. However, there are no mandatory principal payments prior to the maturity. During the first quarter of 2003, the Company received $120,000 in rent which was used for principal payments. As of March 31, 2003, the balance due on this loan was $1,790,000. The drilling contractor has an option to buy the drilling rig from the Company prior to June 2006 for a cash payment equal to the loan balance when the option is exercised.

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Results of Operations—Comparison of the Three Months Ended March 31, 2003 and 2002

The Company incurred a net loss of $2,715,000 for the three months ended March 31, 2003, compared to a net loss of $1,583,000 for the three months ended March 31, 2002. The greater net loss for the three months ended March 31, 2003 is primarily due to a $673,000 increase in interest expense and a $359,000 increase in operating expenses. Interest expense increased by approximately $420,000 as a result of expensing loan issuance and break-up costs for a $25 million loan scheduled to close in the first quarter of 2003 that was replaced by the STEL credit facilities, which the Company believes have more favorable terms. The remaining interest expense increase was due to higher loan balances in 2003. Operating expense increases were caused primarily by increases in the production and sale of gas in Australia. The table below provides a comparison of operations for the three months ended March 31, 2003 with those of the prior year’s quarter.

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Revenues and Sales Volumes

Gas volumes sold in Australia increased 33% due to increased gas sales from existing wells, new wells drilled and an increase in gas deliveries, despite unusual pipeline maintenance in February 2003 that reduced net volumes for that month by approximately 85,000 Mcf (9%) compared to January and March 2003 sales levels. Gas revenues in Australia increased by 40% due to the increase in sales volumes, an increase in the average sales price received and to changes in exchange rates. The Company’s gas sales contracts in Australia are long-term fixed price contracts with yearly adjustments for inflation. The 14% increase in average gas sales price in Australia is due primarily to the inflation adjustments and due to a 7% approximate increase in the value of the Australian dollar in exchange for U.S. dollars.

In natural gas production operations, joint owners sometimes sell more or less than the production volumes to which they are entitled based on their revenue ownership interest. The joint operating agreement includes gas balancing provisions to govern production allocations in this situation. The Company records a natural gas imbalance in other liabilities if any excess takes of natural gas exceed its remaining proved reserves for the property. As of March 31, 2003, 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 1,283,000 Mcf. Based on the average price of $1.32 per Mcf received during 2003 from these sales, this represents $1,694,000 in gas revenues. No liability has been recorded for the excess volumes taken as they do not exceed the Company’s share of remaining proved reserves. Under the terms of the gas balancing agreement, the Company may be required to reduce the monthly volumes it sells by up to 50% of its entitled share of sales, to enable underproduced parties to sell more than their entitled share of the gas sales and cure the imbalance. Any reduction in monthly volumes will negatively affect the Company’s revenues, and operating expenses will not decline proportionately.

During the first quarter of 2003, the Company had minimal domestic revenue. Domestic revenues and volumes in 2002 relate to the West Buna field which the Company sold in the second quarter of 2002.

Costs and Expenses

Operating expenses in Australia increased 66% due to an increase in the number of producing wells, increased costs associated with delivering increasing gas volumes and a 7% approximate decrease in the value of the U.S. dollar in exchange for Australian dollars. Operating expenses also increased due to the Company’s increase in ownership in the Comet Ridge project in mid-2002. Australian oil and gas property DD&A expense increased 14% due to increasing sales volumes, offset by improvements in the DD&A rate as a result of a decline in future development costs per well.

Domestic operating expenses in the first quarter of 2003 are largely attributable to the Lay Creek coal bed methane project where the initial ten wells are in the early dewatering phase. Without these Lay Creek operating expenses the average domestic lifting cost per Mcf sold would be reduced substantially to $2.10 per Mcf. Operating expenses in the first quarter of 2002 includes expenses from the West Buna field. Domestic DD&A expenses decreased due to the aforementioned sale of the Company’s West Buna field.

General and administrative (“G&A”) expenses for the first quarter of 2003 were flat when compared to the three months ended March 31, 2002. For the first quarter of 2003, increased G&A costs associated with taking over operations at Comet Ridge were offset by a significant decline in legal costs as compared to the first quarter of 2002.

Other Income (Expense)

Interest expense increased to $1,305,000 from $632,000, due primarily to the one-time expensing of approximately $420,000 associated with loan issuance and break-up costs for a $25 million loan scheduled to close in the first quarter of 2003 that was replaced by the STEL credit facilities, which the Company believes have more favorable terms to the Company. Interest expense also increased due to increased loan balances in the first quarter of 2003 when compared to the same period in 2002.

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Item 3.    Not Applicable

Item 4.    Controls and Procedures

Management of the Company recognizes its responsibility for maintaining effective and efficient internal controls and disclosure controls (the controls and procedures by which the Company ensures that information disclosed in annual and quarterly reports filed with the Securities and Exchange Commission (“SEC”) is accurately processed, summarized and reported within the required time period). The Company has procedures in place for gathering the information that is needed to enable the Company to file required reports with the SEC. The Company has a group of officers who are responsible for reviewing all quarterly and annual SEC reports. This group consists of the Company’s management, including its Chief Executive Officer, Chief Financial Officer, Senior Vice President, and Executive Vice President—Corporate Development.

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

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

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PART II— OTHER INFORMATION

Item 1.    Legal Proceedings

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

Item 2.     Changes in Securities and Use of Proceeds

None

Item 3.     Defaults Upon Senior Securities

None

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

None

Item 5.     Other Information

None

Item 6.     Exhibits and Reports on Form 8-K

(a)  Exhibits:

Filed in Part I

Filed in Part II

The other material contracts of the Company are incorporated herein by reference from the exhibit list in the Company’s Annual Report on Form 10-KSB for the year ended December 31, 2002.

(b)  Reports on Form 8-K:

None

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SIGNATURES

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

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Certification of Chief Executive Officer

of Tipperary Corporation Pursuant to Section 302

of the Sarbanes-Oxley Act of 2002

I, David L. Bradshaw, certify that:

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

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

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

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

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

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

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

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

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

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

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

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Certification of Chief Financial Officer

of Tipperary Corporation Pursuant to Section 302

of the Sarbanes-Oxley Act of 2002

I, Joseph B. Feiten, certify that:

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

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

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

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

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

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

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

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

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

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

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

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