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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549

FORM 10-K

Commission file number 1-7796

TIPPERARY CORPORATION
(Name of registrant as specified in its charter)

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE

Indicate by check mark whether the issuer (1) has filed all reports required to be filed by Sections 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 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

Check if there is no disclosure of delinquent filers pursuant to Item 405 of Regulation S-K in this form and no disclosure will be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes o    No ý

Aggregate market value of common stock held by non-affiliates of the registrant was $53,973,000 based on the closing price of $3.59 share as of June 30, 2004.

Shares of the registrant's common stock outstanding as of March 9, 2005: 41,355,994 shares.

Documents incorporated by reference and the Part of the Form 10-K into which the document is incorporated: Definitive Proxy Statement for the 2005 Annual Meeting of Shareholders to be filed within 120 days after the year ended December 31, 2004 (Part III).

PART I

ITEMS 1 AND 2. DESCRIPTION OF BUSINESS AND PROPERTIES

GENERAL

In this annual report on Form 10-K, 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.

We are principally engaged in the exploration for, and development and production of, natural gas. We are primarily focused on coalseam gas properties, with our major producing property located in Queensland, Australia. We also hold exploration permits in Queensland and are involved in natural gas exploration and production in the United States with three projects in Colorado and two projects in Nebraska. We seek to increase our reserves through exploration and development projects, but occasionally may do so through the acquisition of producing properties as well.

We were organized as a Texas corporation in January 1967 and maintain our principal executive offices at 633 Seventeenth Street, Suite 1550, Denver, Colorado 80202. In addition, we lease office space at 952 Echo Lane, Suite 375, Houston, Texas 77024, and at Level 20, 307 Queen Street, Brisbane, Queensland 4000, Australia.

All of our public filings may be read and copied at the SEC Public Reference Room at 450 Fifth Street, N.W., Washington, DC 20549, or viewed at the SEC's website at www.sec.gov. Information on the SEC Public Reference Room may be obtained by calling 1-800-732-0330. We also maintain an internet site at www.tipperarycorp.com providing access to our recent public filings. Our website is not part of this Form 10-K.

This Form 10-K 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 economy, and about the Company itself. Words such as "may," "will," "expect," "anticipate," "estimate" or "continue," or comparable words are intended to identify the forward-looking statements. These statements are not guarantees of future performance and involve numerous 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 the 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.

Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:

•

changes in our production or sales volumes;



•

worldwide supply and demand for oil and gas which affect their prices;



•

competing supplies of gas in Australia;



•

the timing and extent of our success in discovering, acquiring, developing and producing oil and natural gas reserves;



•

future production and development costs;



•

our ability to obtain financing for our proposed activities;



•

the effect of existing and future laws, governmental regulations and the political and economic climate of the United States and Australia;



•

conditions in the capital markets, and

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•

our ability to obtain and continue gas sales contracts in Australia.

For a discussion of these and other risks related to the forward-looking statements contained herein, please see "Risk Factors" discussed later in this section.

BUSINESS ACTIVITIES

Australia

Our activities in Australia are conducted substantially through our 90%-owned Australian subsidiary, Tipperary Oil & Gas (Australia) Pty Ltd ("TOGA"). As of December 31, 2004, 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 76,700 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, the policy of the Queensland DNRM allows the ATP holder to renew the ATP for an additional four year exploratory period and generally requires the holder to relinquish a 20% portion of ATP acreage not held by a petroleum lease. ATP 526 was renewed in November 2004 for another four-year exploration term which expires on October 31, 2008. The terms of the renewal did not require any relinquishment of acreage. ATPs 653, 655 and 745 have initial terms expiring on September 30, 2006, October 31, 2007 and November 1, 2007, respectively.

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. Drilling of the horizontal well commenced in January 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.

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Exploratory and Development Acreage Summary—Australia

⁽¹⁾

This Petroleum Lease entitles the lessee(s) to renew the lease for a second term equal to the lesser of the number of years in the first term or the remaining production life.

⁽²⁾

Expenditure requirements represent the current year minimum capital spending required by the ATP grant terms by the current year annual reporting date for the respective ATP. The annual reporting date coincides with the month and day of the initial term expiration date. Negotiated expenditure requirements vary from year to year.

⁽³⁾

Annual nominal capital expenditure requirements for each Petroleum Lease are approximately $275,000. The expenditure requirements are reduced by governmental royalties paid on gas sales. In 2004, we paid royalties on PL 91 and 92 in excess of the expenditure requirements.

⁽⁴⁾

In connection with the renewal of ATP 526 in November 2004, we expect to receive six new Petroleum Leases. Five of these Petroleum Leases will be associated with ATP 526 and one will be associated with ATP 653.

The following tables summarize well status on the Comet Ridge project as of December 31, 2004 and gross gas production by quarter. In December 2003, we began using a second compression plant facility, which increased the field's gas compression capacity to approximately 38 million cubic feet ("MMcf") per day. Field sales volumes are currently limited by metering equipment to 35 MMcf per day. We are expanding the capacity of our metering equipment, compressors and facilities to a sales capacity of approximately 45 MMcf per day by mid-year 2005.

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Comet Ridge Operations Review

We drilled six exploratory wells on the Comet Ridge project during 2004. The 2004 drilling was substantially funded with borrowings from Slough Trading Estates Limited ("STEL") and a senior credit facility described in Note 4 to the Consolidated Financial Statements. Future 2005 development and exploratory costs are expected to be funded by the existing senior credit facility.

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, tight 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 159,500 acres and is the operator of that portion of the acreage. During 2004, Houston Exploration acquired its interest from Kerr-McGee Rocky Mountain Corporation ("Kerr-McGee"). During 2003, five wells were drilled on the Frenchman project by Kerr-McGee. Three of these wells were completed, and two were plugged and abandoned. In 2004, Tipperary drilled five additional Frenchman wells in which Kerr-McGee elected not to participate, which gave us a 100% interest in these wells. We believe four of these 100% wells will be commercial gas producers, and we have earned 100% of offsetting drill sites as set forth in the operating agreement. We plugged and abandoned the other well drilled. In February 2005 Tipperary completed a gas gathering system at a cost of approximately $350,000 and expects to connect its 100% owned wells to a nearby pipeline and begin selling gas in the second quarter of 2005. We plan to drill during the same quarter at least four additional 100% development wells at a cost of approximately $800,000.

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, also

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acquired from Kerr-McGee, and is the operator of the project. Five wells were drilled on the Republican prospect in 2004. Through March 11, 2005, a total of 24 wells were drilled of which 17 wells were completed and seven were plugged and abandoned. An additional 24 wells are planned to be drilled in the second quarter of 2005 at an estimated net cost to us of $960,000. In the first quarter of 2005, we participated with Houston Exploration in a 3D seismic program covering 99,000 gross acres at a net cost to us of $650,000. We expect gas sales to begin in mid 2005.

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 investigating pipeline connections and are evaluating the possibility of selling gas in 2005. 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 anticipate commencing a drilling program if the results of the seismic interpretation warrant further testing.

Sand Hill—During late 2003, we acquired leasehold acreage in western Nebraska totaling approximately 51,000 gross acres, the "Sand Hill" project. This acreage is located in the vicinity of the Company's 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.

PRODUCING WELLS AND ACREAGE

The following table sets forth information with respect to our producing wells and acreage as of December 31, 2004:

⁽¹⁾

The acreage reported in this table includes only that which is covered by a Petroleum Lease. We also hold, either directly or indirectly, ATPs as previously disclosed in the Exploratory and Development Acreage Summary—Australia. Gross producing gas wells on Petroleum Leases include 21 (15.05 net) wells that were drilled, completed and production tested, but have not yet been connected to the gathering system of the Comet Ridge project.

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⁽²⁾

Our domestic undeveloped leases have various primary terms ranging from five to ten years. The expiration of any leasehold interest or interests would not have a material adverse financial effect on us. However, costs associated with unevaluated acreage that expires or is forfeited could result in a non-cash write-down under the full cost method of accounting. See Critical Accounting Policies discussed under "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

DRILLING ACTIVITIES

Information concerning the number of gross and net wells drilled and completed by us during 2004, 2003 and 2002 is as follows⁽¹⁾:

⁽¹⁾

Wells presented in this table have been drilled, completed and are producing or have undergone extended production testing, or have been determined to be non-commercial (dry). Not included in this table are five wells that are pending completion work and production tests.

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PRODUCTION

The following table summarizes information regarding our average sales price per unit of oil and gas produced, as well as the average operating cost per unit of sales for the years indicated:

SIGNIFICANT CUSTOMERS AND DELIVERY COMMITMENTS

Australia

During the first half of 2004, 100% of our gas sales in Australia were made under a five-year contract effective June 1, 2000 with Energex Retail Pty Ltd ("Energex"), an unaffiliated customer. The Energex contract has delivery requirements of up to approximately 15,000 Mcf of gas per day. During the last half of 2004, we sold gas to four purchasers, including Energex, under various short and long-term contracts. During 2004, we sold 82% of our gas to Energex and 15% to Santos QNT Pty Ltd ("Santos"), an unrelated party.

In December 2004, we signed a 23-month extension to the five-year Energex contract. The extension expires on April 30, 2007. The new contract is similar in terms to the existing contract. On December 23, 2004, we entered into an agreement to supply gas to Orica Australia Pty Ltd ("Orica"), an unrelated party. The contract commences on June 26, 2006 for a term of 10 years and provides that Orica will purchase a minimum of 3,000 and a maximum of 4,800 Mcf of gas per day. On December 30, 2004, we entered into an agreement to supply natural gas to Santos. The contract began on January 1, 2005 for a term of 21 months and provides that Santos will purchase a minimum of 7,700 and a maximum of 9,700 Mcf of gas per day. We have entered into additional agreements with Energex and CS Energy whereby they may purchase gas under spot sale arrangements. We have a gas sales agreement with Origin Energy Retail Limited ("OERL"), a subsidiary of Origin Energy Limited, to supply approximately 9 Bcf per year, or approximately 25,000 Mcf of gas per day net to the Company's interest, for 13 years beginning May 2007. Origin Energy Limited is a large Australian integrated energy company which, through subsidiaries, owns nearly 24% of the Comet Ridge project. All of the partners in the Comet Ridge project have elected to participate in the sales agreements we entered into with OERL and the sales agreements entered into with Energex, Orica and Santos in December 2004.

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

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United States

In the United States, we have sold our oil and gas production to several purchasers during the past several years, generally under short-term contracts. During 2002, 2003 and 2004, we did not have material domestic oil or gas sales.

PRICING

Australia

During 2004, we sold gas to four purchasers in Australia. Our average price in Australia during 2004 was $1.75 per Mcf. In Australia prices obtained under sales contracts have generally been under long-term fixed price contracts with adjustments for inflation, however, during 2004 we began sales under several short term contracts of one year or less. Contract prices vary, among other reasons, due to the delivery point of gas sold. Natural gas prices in Australia over the last several years have been relatively stable. Exchange rates, however, have had the effect of causing price volatility on our sales revenues. Future natural gas contract prices are subject to variability due to regional supply and demand. The longer term contracts typically provide for a fixed price with consumer price index escalators. Gas prices in the future may also be influenced by worldwide liquefied natural gas ("LNG") prices as the LNG industry develops.

United States

Oil and natural gas prices are subject to significant fluctuations. Natural gas prices in the United States fluctuate based primarily upon weather patterns and regional supply and demand, and crude oil prices fluctuate based primarily upon worldwide supply and demand. We have occasionally used derivatives in the past to hedge risks associated with the volatility of oil and gas prices in the United States. None of our production has been hedged since 2000. See the discussion of hedging activities in Note 1 to the Consolidated Financial Statements. We anticipate commencing significant U.S. gas sales in the second quarter of 2005. Gas prices may be hedged in the future, and are influenced by weather-related and other supply and demand factors. We believe that, to a growing extent, gas prices will be affected by LNG prices as well.

RISK FACTORS

Our operations are subject to a variety of material risks, including the following:

Our major shareholder intends to divest all or a portion of its ownership interest in the near term.

For the past several years, a significant source of liquidity as well as our long term financing has been debt and equity financing provided by Slough Estates USA Inc. ("Slough"), our majority shareholder, and its affiliates. We do not know the ultimate outcome of Slough's divestiture plans. While Slough has committed to support us with long-term loans or equity contributions through April 2006, we do not know what alternative financing or equity investments will be available from other parties after any divestiture occurs, if at all. Any alternative financing we obtain after Slough's divestiture may not be available or, if available, could be on terms not as favorable as Slough was able to provide. We have a $150 million AUD senior credit facility with two major Australian financial institutions that Slough Estates plc (Slough's parent company) has guaranteed. Slough cannot assign this guarantee nor substantially divest of our stock without approval from the Australian financial institutions.

We need to attract and retain purchasers for our future gas production in Australia.

Our gas revenues from our sole producing gas property in Australia have increased significantly over the past several years and we expect will grow substantially more by 2007 when we start selling significantly more volumes under existing long-term gas sales contracts. However, we will need—and are seeking—

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additional short-term and long-term gas sales contracts so that we can accelerate production and sale of our gas, increase our revenues and generate profits sufficient to repay our long-term Australian debt. We cannot assure that we will obtain such contracts or that the terms will be beneficial to us.

We lack diversification because our business plan is highly concentrated in coalseam gas properties in Queensland, Australia.

Because we lack diversification, our financial results and condition will depend significantly upon the success of our Australian operations. Currently, most of our efforts and resources are being expended on the Comet Ridge coalseam gas project located in Queensland, Australia.

We have incurred significant losses over the past several years and such losses are likely to continue until we have significantly greater natural gas sales.

Over the past four fiscal years we have incurred significant losses, as we have focused our efforts in finding coalseam gas reserves and establishing production facilities in Queensland, Australia. With the recent (i) settlement of the Tri-Star litigation, (ii) significantly improved sales levels in Australia, and (iii) expected significant natural gas sales in the U.S. beginning in 2005, our operating losses in 2005 and 2006 are likely to significantly decline from 2004. We expect losses are likely to continue until sales begin in mid 2007 under a major long-term Australian gas contract. These losses can be expected to deplete our capital and require us to seek additional financing. This risk is heightened due to the uncertainty of future financing because Slough is seeking to sell its interest in us.

We have significant long-term debt and are subject to interest rate risk.

In June 2004, we obtained from two major Australian financial institutions a senior debt facility of $150 million AUD (approximately $117 million USD at current exchange rates) to refinance $100 million AUD of existing debt and further develop the Comet Ridge project. The debt has a variable interest rate and virtually all of our Australian properties are pledged as collateral for the debt. Repayment of this debt will require that we generate significant revenues in the long term. In addition, we will be subject to significant interest rate risk on our debt because rates could increase and costs to refinance the debt could be expensive.

The eastern Australian gas market is in an ongoing development stage.

If, as we develop and expand production of our Australian gas reserves, the eastern Australian market for gas does not continue to develop and grow, the market's gas prices may soften or our production volumes may exceed demand by available markets. This could negatively impact our revenues, results of operations, financial condition and cash flows.

Loss of revenue from any of our customers could negatively affect our results of operations.

Our Australia natural gas sales during 2004 have been made to four purchasers under various short and long-term contracts. Loss of revenue from any of our Australian gas customers for any reason, including nonpayment, could have a negative impact on our results of operations, financial condition or cash flows.

Our exploration rights in Australia are subject to renewal at the discretion of the government.

Gas exploration in Queensland, Australia is conducted under an ATP which is granted at the discretion of the Queensland DNRM Minister. Each ATP requires the expenditure of a set amount of exploration costs, and is generally subject to renewal every four years. On renewal of an ATP, the Minister may require reduction of the area to which the ATP applies. We cannot assure that our ATPs will be renewed. Non-renewal or loss of an ATP could adversely affect our exploration and development plans, results of operations, financial condition or cash flows.

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We may be negatively impacted by the currency exchange rate between United States and Australia.

We may experience losses from fluctuations in the exchange rate between the Australian dollar and the U.S. dollar. Currently, nearly all of our revenues are generated from natural gas sales denominated in Australian currency. Therefore, foreign currency fluctuations impact our reported U.S. revenues. In addition, with currency fluctuations, our future financial statements will reflect fluctuations in our Australian oil and gas property accounts and debt repayable in Australian currency.

Sales of outstanding shares may hurt our stock price.

The market price of our common stock could fall substantially if our stockholders sell large amounts of our common stock. The possibility of such sales in the public market may also decrease the market price of our common stock. As of December 31, 2004, we had 41,355,994 shares of common stock outstanding. Potential future sales of our common stock include 33,733,920 shares beneficially held by our officers, directors and principal stockholders, comprised of common stock held and options and warrants, assuming their full exercise, representing 75.2% of the total number of shares then outstanding. In addition, the daily trading volume of our common stock has not been significant for the past several years. Any continuous or large sales of our common stock in the open market can be expected to adversely affect our share price.

Existing principal stockholders and management own a significant amount of our outstanding stock which gives them control of our activities.

Existing principal stockholders and management own 74.5% of the outstanding shares of our common stock. Such persons, as a practical matter, control our operations as they are able to elect all members of our board of directors. Our largest stockholder, Slough Estates USA, Inc., owns 54.5% of our outstanding common stock, which gives it the right to control us. Thus, other stockholders will have little practical ability to change the management or direction of the company.

Exercise of outstanding warrants and options may dilute current stockholders.

Our outstanding warrants and options could inhibit our ability to obtain new equity because of reluctance by potential equity holders to absorb potential ownership dilution as well as dilution in share value. As of December 31, 2004, we had warrants and options outstanding to purchase 3,473,900 shares of our common stock at a weighted average exercise price of $2.45 representing 7.7% of the outstanding shares of common stock, assuming their full exercise. These warrants and options enable the holder to profit from a rise in the market value of our common stock with potential dilution to the existing holders of common stock.

We face significant operating risks which may not be insurable.

Our exploration, drilling, production and transportation of gas and other hydrocarbons can be hazardous. Unforeseen occurrences can happen, including property title uncertainties, unanticipated pressure or irregularities in formations, blowouts, cratering, fires and loss of well control, which can result in damage to or destruction of wells or production facilities, injury to persons, loss of life or damage to property or the environment. We maintain insurance against certain losses or liabilities arising from our operations in accordance with customary industry practices and in amounts that our management believes to be prudent. However, insurance is not available for all operational risks, such as the market risks we face in Australia. The occurrence of a significant event that is not fully insured could negatively impact our results of operations, financial condition and cash flows.

We are dependent upon the services of our President and Chief Executive Officer.

We are highly dependent on the services of our President, Chief Executive Officer and Chairman of the Board, David L. Bradshaw. We entered into an employment agreement with Mr. Bradshaw on September 18, 2001. This agreement automatically renews every two years unless terminated under the

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terms of the agreement. We do not carry any key man life insurance on Mr. Bradshaw. The loss of his services could negatively impact our operations.

Any hedging activities we engage in may prevent us from realizing the benefits in gas or oil price increases.

To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of price increases above the levels of the hedges during certain time periods. In the past, we have periodically engaged in hedging activities with respect to some of our domestic oil and gas production through a variety of financial arrangements designed to protect against price declines, including swaps and futures contracts. We currently are not a party to any hedging contracts, but may engage in hedging in the future.

Competing supplies of gas in Australia could be detrimental to our revenues.

Alternative large-scale supplies of natural gas, whether from within or outside of Queensland, would significantly affect the future supply of natural gas in the Queensland market, the area of our primary focus. For example, a potential 1,988-mile gas pipeline that would connect Queensland with Papua New Guinea's southern highlands fields has experienced varying degrees of interest within the industry for several years. Papua New Guinea producers recently reported that they had agreed to proceed with a $100 million Front End Engineering and Design study to assist in evaluating the commercial feasibility of constructing such a pipeline. Completion of any such pipeline project or the availability of other gas supplies could lower the price of natural gas and as a result, adversely impact our revenues.

Our reported reserves of gas represent estimates which may vary materially over time due to many factors.

Generally.    Our estimated reserves may be subject to downward revision based upon future production, results of future development, prevailing gas prices, foreign exchange rates, operating and development costs, ability to market and other factors. There are uncertainties and uncontrollable factors inherent in estimating quantities of oil and gas reserves; projecting future rates of production, and the timing of development expenditures.

In addition, the estimates of future net cash flows from our proved reserves and the present value of such reserves are based upon various assumptions about future production levels, prices and costs that may prove to be incorrect over time. Any significant variance from the assumptions could result in material differences in the actual quantity of our reserves and amount of estimated future net cash flows from our estimated oil and gas reserves.

Ceiling Test.    We account for our oil and gas properties using the full cost method. Under this method, we are required to record a permanent impairment provision if the net book value of our oil and gas properties (net of related deferred taxes) exceeds a ceiling value equal to the sum of (i) the present value of the future cash inflows from proved reserves, tax effected and discounted at 10% per annum, and (ii) the cost of unevaluated properties. The ceiling test is computed by country and at the end of each quarter. The oil and gas prices used in calculating future cash inflows in the United States are based upon the market price on the last day of the accounting period. Oil and gas prices are generally volatile, and if the market prices at a period end date have decreased, we may have to record an impairment. A loss may also be generated by the transfer of significant early stage exploratory costs to the oil and gas property cost pool that is subject to the ceiling test. These losses typically occur when significant costs are transferred to the oil and gas property cost pool as a result of an unsuccessful project without commercially productive oil and gas production. The costs of our Australian properties are recorded in a separate full cost pool, as required under the full cost method. The prices received for sales in Australia, which are used to calculate future cash inflows, are primarily based on short-term spot prices and fixed prices received at the end of the accounting period for existing long-term contracts. However, while there is less volatility with respect

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to the price received in Australian dollars, any volatility in the exchange rate affects the U.S. dollar equivalent price received as well as the carrying value of our Australian properties and exposes us to a potential impairment.

We are subject to political and economic risks with respect to our Australian operations.

Our primary operations are in Australia, where we conduct natural gas exploration, development and production activities, which may be subject to:

•

political and economic uncertainties, including changes, sometimes frequent or marked, in governmental energy and environmental policies or the personnel administering them;



•

cancellation or modification of contract rights, and



•

royalty and tax increases and other risks arising out of governmental sovereignty over the areas in which we conduct our operations.

Consequently, our Australian operations may be substantially affected by factors beyond our control, any of which could negatively affect our financial results. Further, in the event of a dispute in Australia in relation to the Comet Ridge project, we may be subject to the exclusive jurisdiction of Australian courts or we may not be successful in subjecting non-U.S. persons to the jurisdiction of courts in the U.S., either of which could adversely affect the outcome of a dispute.

We have limited control over development of most of our U.S. properties because we are not the operator of those properties.

As the non-operating minority owner of working interests in the United States, we do not have the right to direct or control the drilling and operation of wells on the properties. As a result, the rate and success of the drilling and development activities on these properties operated by others may be affected by factors outside of our control, including:

•

the timing and amount of capital expenditures;



•

the operator's business and technical expertise and financial resources; and



•

the selection of suitable technologies for certain operational activities.

If the operators of these properties do not reasonably and prudently drill and develop these properties, then the value of our working interests would likely be negatively affected.

Our board of directors can issue preferred stock with terms that are preferential to our common stock.

Our board of directors may issue up to 10 million shares of cumulative preferred stock and up to 10 million shares of non-cumulative preferred stock without action by our stockholders. The board of directors has the authority to divide the two classes of preferred stock into series and to fix and determine the relative rights and preferences of the shares of any series. Rights or preferences could include, among other things:

•

the establishment of dividends which must be paid prior to declaring or paying dividends or other distributions to our common stockholders;



•

greater or preferential liquidation rights which could negatively affect the rights of common stockholders, and



•

the right to convert the preferred stock at a rate or price which would have a dilutive effect on the outstanding shares of common stock.

In addition, the ability of our board of directors to issue preferred stock could impede or deter unsolicited tender offers or takeover proposals.

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We face significant risks that natural gas property acquisition and development will not meet expectations or will subject us to unforeseen environmental liability.

While we perform a review of records and properties consistent with industry practices prior to acquiring any gas and oil property, reviews of this type are inherently incomplete. Generally it is not feasible to review in-depth every individual property involved in each acquisition. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we may be required to assume certain environmental and other risks and liabilities in connection with properties. There are uncertainties inherent in estimating quantities of proved oil and gas reserves and actual future production rates and associated costs with respect to acquired properties, and actual results may vary substantially from those assumed in the estimates. Therefore, while our current operations do not include the acquisition of developed properties, future acquisitions may have a negative effect upon our operating results.

Increased uncertainty due to terrorist attacks and war.

Terrorist acts or acts of war may negatively impact our results of operations, financial condition, ability to raise capital or future growth. The potential for future terrorist attacks, the national and international responses to terrorist attacks or perceived threats to national security, and other acts of war or hostility have created economic and political uncertainties that could adversely affect our business and operating results in ways that we cannot possibly predict. We are not insured for losses and interruptions caused by acts of war and have partial insurance for losses due to terrorist acts.

Significant governmental regulations and related legal considerations increase our operating costs and subject us to potential significant liability.

Australian Regulations

Commonwealth of Australia Regulations.    The regulation of the oil and gas industry in Australia is similar to that of the United States, in that regulatory controls are imposed at both the commonwealth (national) and state levels. Specific commonwealth regulations impose environmental, cultural heritage and native title restrictions on accessing resources in Australia. These regulations are in addition to any state level regulations. Native title legislation was enacted in 1993 in order to provide a statutory framework for deciding questions such as where native title exists, who holds native title and the nature of native title which were left unanswered by a 1992 Australian High Court ("Court") decision. The Commonwealth and Queensland State governments have passed amendments to this legislation to clarify uncertainty in relation to the evolving native title legal regime in Australia created by the decision in a 1996 Court case. Each authority to prospect, petroleum lease and pipeline license must be examined individually in order to determine validity and native title claim vulnerability.

State of Queensland Regulations.    The regulation of exploration and recovery of oil and gas within Queensland is governed by state-level legislation. This legislation regulates access to the resource, construction of pipelines and the royalties payable. There is also specific legislation governing cultural heritage, native title and environmental issues.

Environmental Matters.    Environmental matters are highly regulated at the state level, with most states having in place comprehensive regulations. In particular, petroleum operations in Queensland must comply with the Environmental Protection Act and any conditions attaching to the petroleum lease, authority to prospect or pipeline license (as the case may be). We have incurred costs of approximately $191,000, $146,000 and $35,000 in 2004, 2003 and 2002, respectively, in Australia to comply with environmental regulations. In the fourth quarter of 2003, the Queensland government notified us that

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exploration and production of gas from under national park lands would be limited to using surface facilities located outside the parks. If gas reserves are discovered under park lands, they may be recovered using directional drilling from drill sites adjacent to park lands. Management believes directional drilling can be used effectively at Comet Ridge in lieu of drilling from inside the parks. Management does not expect these new requirements to significantly increase future exploration, development and operating costs. Three of our productive wells and one ATP 526 exploration well were previously permitted on park lands. Under current government policy, the four wells will be plugged and abandoned, and the surface area reclaimed at an estimated cost to us of approximately $100,000. We expect to recover these wells' reserves using directional drilling. The amount of reserves under park lands is not currently known. There can be no assurance that environmental laws and regulations will not become more stringent in the future or that we will not incur significant costs in the future to comply with these laws and regulations.

Australian Crude Oil and Gas Markets.    The Australia and Queensland onshore crude oil and gas markets are not regulated. However, a national regulatory framework for the natural gas market in Australia has recently been established (on a state by state basis). The National Gas Access Regime (the "Regime") has been developed by a group of government and oil and gas industry representatives. Among the objectives of the Regime are to provide a process for establishing third party access to natural gas pipelines, to facilitate the development and operation of a national natural gas market, to promote a competitive market for gas in which customers are able to choose their supplier, and to provide a right of access to transmission and distribution networks on fair and reasonable terms and conditions. We cannot currently ascertain the impact of the Regime, but believe it should benefit us.

United States Regulations

General.    The production, transmission and sale of crude oil and natural gas in the United States is affected by numerous state and federal regulations with respect to allowable well spacing, rates of production, bonding, environmental matters and reporting. Future regulations may change allowable rates of production or the manner in which oil and gas operations may be lawfully conducted. Although oil and gas may currently be sold at unregulated prices, such sales prices have been regulated in the past by the federal government and may be again in the future.

State Regulation.    Oil and gas operations are subject to a wide variety of state regulations. Administrative agencies in such jurisdictions may promulgate and enforce rules and regulations relating to virtually all aspects of the oil and gas business.

Environmental Matters.    Our business activities are subject to federal, state and local environmental laws and regulations. Compliance with these regulations increases our overall cost of doing business. These costs include production expenses primarily related to the disposal of produced water and the management and disposal of other wastes associated with drilling for and production of hydrocarbons. We incurred costs of approximately $104,000, $102,000 and $51,000 in 2004, 2003 and 2002, respectively, in the United States to comply with environmental regulations. We continue to monitor our environmental compliance. There can be no assurance that environmental laws and regulations will not become more stringent in the future or that we will not incur significant costs in the future to comply with these laws and regulations.

EMPLOYEES

At December 31, 2004, we employed 13 persons in the United States and 49 persons in Australia on a full-time basis, including our officers. None of our employees are represented by unions. We consider our relationship with our employees to be good.

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ITEM 3. LEGAL PROCEEDINGS

Until December of 2004, we and two unaffiliated working interest owners were 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 ("Tri-Star litigation"). The plaintiffs alleged, 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 amended pleadings denying liability and raising a number of affirmative defenses and asserting various counterclaims. TOGA operated the project beginning in March 2002, after the court entered a Writ of Temporary Injunction (the "Injunction") to enforce the votes of a majority-in-interest of the parties under the joint operating agreement to remove Tri-Star as operator and replace it with TOGA.

On October 30, 2004, we entered into a settlement agreement with Tri-Star covering this litigation, as well as all other litigation between those parties originating in Queensland, Australia. Pursuant to the settlement agreement we will continue as operator, and Tri-Star has transferred to us 96% and two unrelated intervening plaintiffs the remaining 4% of each of the registered titles for the Comet Ridge project held in its name, including, but not limited to, the relevant Authorities to Prospect and Petroleum Leases. Tri-Star has transferred to a newly-formed subsidiary of Tipperary Corporation, Tipperary Queensland, Inc., a 2.25% working interest in the Comet Ridge project, subject to a contractual overriding royalty interest that approximates 2.5% of Tipperary's future Comet Ridge revenues (net of pipeline tariffs) and is equivalent to 1.5% of all Comet Ridge gas produced and sold. The transfer of the registered titles has been completed. Under the settlement agreement we have paid $5.0 million to Tri-Star, using existing cash and TOGA's Australian loan facility. In addition to other provisions, the settlement agreement provides that all claims made by us, Tri-Star and the individual defendants are to be dismissed without ability to refile. The order actually dismissing the claims was signed on December 15, 2004. We, the individual defendants and Tri-Star have each released each other from liability for any claims that were or could have been asserted in the litigation, whether known or unknown.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

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PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Our common stock is listed and has been trading on the American Stock Exchange since April 1992. As of March 9, 2005, there were approximately 1,600 holders of record of our common stock. The table below sets forth the high and low closing prices for the common stock of the Company for the periods indicated:

We have not paid any cash dividends on our common stock and do not expect to pay any dividends in the foreseeable future. We intend to retain any earnings to provide funds for operations and expansion of our business.

SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

The table below provides certain information as of December 31, 2004 with respect to compensation plans under which our equity securities are authorized for issuance:

At December 31, 2004, we had 1,201,900 warrants outstanding to directors, employees and non-employees. From time to time, we have offered warrants to directors and employees as an incentive to provide long-term service to us. The terms of each warrant are negotiated. Less frequently, we have offered warrants to consultants as part of their compensation agreements.

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ITEM 6. SELECTED FINANCIAL DATA

The selected consolidated financial information presented below for the years ended September 30, 2000 through December 31, 2004 is derived from our Consolidated Financial Statements.

Sales and impairments of oil and gas properties, write-offs of deferred loan costs and impairments of oil and gas properties in certain years materially affect the comparability of the financial information presented below. This information should be read in conjunction with the Consolidated Financial Statements and associated Notes and Management's Discussion and Analysis of Financial Condition and Results of Operations.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

GENERAL

The following is a discussion of our financial condition and results of operations. This discussion should be read in conjunction with our Consolidated Financial Statements and the Notes thereto.

This discussion and analysis of financial condition and results of operations, and other sections of this Form 10-K, contain 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 economy and about our Company. Words such as "may," "will," "expect," "anticipate," "estimate" or "continue," or comparable words are intended to identify the forward-looking statements. These statements are not guarantees of future performance and involve numerous 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, projected or forecasted in the 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.

Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to, changes in our production or sales volumes, worldwide supply and demand for oil and gas which affect their prices, competing supplies of gas in Australia, the timing and extent of our success in discovering, acquiring, developing and producing oil and natural gas reserves, risks inherent in the drilling and operation of oil and natural gas wells, future production and development costs, our ability to obtain financing for proposed activities, the effect of existing and future laws, governmental regulations and the political and economic climate of the United States and Australia, conditions in the capital markets, as well as our ability to obtain and continue gas sales contracts in Australia. For a discussion of these and other risks related to the forward-looking statements contained herein, please see "Risk Factors" as discussed in Items 1 and 2 of this Form 10-K.

OIL AND GAS RESERVES

At December 31, 2004, our total proved gas reserves were estimated to be 581 billion cubic feet ("Bcf"), of which 578 Bcf are attributed to our Comet Ridge Project in Queensland, Australia and 3 Bcf are attributed to domestic reserves located in our Frenchman and Republican projects. As of December 31, 2004, we had no oil reserves. Proved gas reserves, as defined by SEC regulation, are the estimated quantities of natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e. prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Accordingly, proved reserves do not reflect potentially higher prices under conditional contract provisions.

Using current market product prices in effect at such time and a discount rate of 10% as prescribed by SEC regulation, our total discounted future after-tax net cash flows were estimated to be $144.0 million as of December 31, 2004, compared to $107.6 million at December 31, 2003. The net increase in our discounted cash flows was due primarily to (i) extensions and discoveries at Comet Ridge and in Colorado and (ii) favorable changes in prices and production costs at our Comet Ridge project.

The present value of future net cash flows does not purport to be an estimate of the fair market value of our proved reserves. An estimate of the future value would also take into consideration, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money and the risks inherent in producing gas.

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CRITICAL ACCOUNTING POLICIES

Our financial statements are based on the selection and application of significant accounting policies, some of which require management to make estimates and assumptions which affect the reported amounts of assets, liabilities, revenues and expenses and also affect the disclosure of contingent items. We believe that the following are some of the more critical judgment areas in the application of our accounting policies that currently affect our financial condition and results of operations.

Oil and Gas Reserves

Estimated reserve quantities and estimated future development costs are used to calculate the rate at which we record depreciation, depletion and amortization (DD&A) expense. The process of estimating quantities of proved reserves is inherently uncertain, and the estimates of future net cash flows and their present values from our proved reserves are based upon various assumptions about future production levels and current prices and costs. Any significant variance from the assumptions could result in material differences in the actual quantity of our reserves and amount of estimated future net cash flows from the estimated oil and gas reserves. The discounted after-tax future net cash flows from the estimated reserve quantities impact the recorded value of our full cost pools as discussed below. If the estimate of proved reserve volumes declines or the estimate of future development costs increases, the DD&A expense we record increases, reducing net income. Certain early stage exploratory costs are excluded from costs subject to the DD&A calculation. We evaluate these excluded costs quarterly, and the costs are added to the DD&A base if we determine the costs will or will not result in commercially productive oil or gas production.

Full Cost Method of Accounting for Oil and Gas Properties

We account for our oil and gas properties using the full cost method. Under this method, we are required to record a permanent impairment provision if the net book value of our oil and gas properties (net of related deferred taxes) exceeds a ceiling value equal to the sum of (i) the present value of the future cash inflows from proved reserves, tax effected and discounted at 10% per annum, and (ii) the cost of unevaluated properties. The ceiling test is computed by country and at the end of each quarter. The oil and gas prices used in calculating future cash inflows in the United States are based upon the market price on the last day of the accounting period. Oil and gas prices are generally volatile; and if the market prices at a period end date have decreased, we may have to record an impairment. A loss may also be generated by the transfer of significant early stage exploratory costs to the oil and gas property cost pool that is subject to the ceiling test. These losses typically occur when significant costs are transferred to the oil and gas property cost pool as a result of an unsuccessful project without commercially productive oil and gas production.

The cost of our Australian properties is recorded in a separate full cost pool, as required under the full cost method. The prices received for sales in Australia, which are used to calculate future cash inflows are primarily based on short-term spot prices at the end of the accounting period and fixed prices received under existing long-term contracts. However, while there is less volatility with respect to the price received in Australian dollars, any volatility in the exchange rate affects the U.S. dollar equivalent price received and exposes us to a potential recorded loss in value.

In the event we record a reduction in our discounted after-tax future net cash flow from lower estimated reserve quantities, we could be required to record a non-cash loss. In addition, we could record a non-cash loss if costs associated with our domestic exploration projects are added to depletable costs within the domestic full cost pool without sufficient associated oil and gas reserves. While our oil and gas properties are subject to impairments based on product price declines, subsequent increases in value due to price increases will not be recorded. Subsequently, however, we would record a lower DD&A expense, since the prior impairment would have reduced the net book value of the full cost pool.

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Contingencies

We account for contingencies in accordance with Statements of Financial Accounting Standards No. 5, "Accounting for Contingencies," which requires that we record an estimated loss from a loss contingency when information available prior to issuance of our financial statements indicates that it is probable that an asset has been impaired or a liability has been incurred at the date of the financial statements and the amount of the loss can be reasonably estimated. Accounting contingencies require us to use our judgment, and while we believe that our accruals for these matters are adequate, if the actual loss from the loss contingency is significantly different than the estimated loss, our results of operations of will be impacted in the period the contingency is resolved.

RECENT ACCOUNTING PRONOUNCEMENTS

See Note 1 to the Consolidated Financial Statements for recent accounting pronouncements and how we anticipate they will impact our financial statements.

LIQUIDITY AND CAPITAL RESOURCES

We have used equity and debt financings and sales of producing properties to fund most of our capital expenditures and operations during the last few years. These capital expenditures included the acquisition of additional interests in the Comet Ridge project in Queensland, Australia.

During 2004, we used $13.2 million of cash in operating activities and invested $15.9 million in capital expenditures and $5.0 million to purchase the registered titles in the Comet Ridge project in conjunction with the settlement of the Tri-Star litigation. See Note 12 to the Consolidated Financial Statements. Our operating activities and capital investments were funded with $26.6 million in net proceeds from debt financing and $8.3 million in proceeds from the sale of common stock.

Debt financing during 2004 consisted of approximately $17.7 million and $15.6 million received from Slough Trading Estates Limited ("STEL") and an Australian bank senior credit facility, respectively. These funds were primarily used for continued development of the Comet Ridge project and exploration of acreage within ATP 526. In addition, we borrowed $68.2 million from our senior credit facility to retire STEL debt of the same amount. See Note 2 to the Consolidated Financial Statements.

At December 31, 2004, we owed Slough Estates USA Inc. ("Slough") $4 million. The loan is due in April 2006 and bears an interest rate of LIBOR (2.306% as of December 31, 2004) plus 3.5%.

We have various commitments in addition to our long-term debt. The following table summarizes our contractual obligations at December 31, 2004 (in thousands):

⁽¹⁾

Senior credit facility based on financing institutions' latest repayment model (May 2004).

⁽²⁾

Based on December 31, 2004 weighted average interest rate of 6.31% and anticipated debt repayment.

⁽³⁾

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

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The table below provides an analysis of our capital expenditures of $20.9 million during the year 2004.

Capital Expenditures Activity in 2004
(in thousands)

Exploration and Development Drilling Commitments

Our anticipated capital expenditures during 2005 total approximately $28.5 million. In Australia, we expect to incur capital costs of $20 million of which $17 million would be for development drilling and for gas gathering and water disposal facilities and the remaining amount would be for exploration activities on ATP 653 and ATP 655. Capital spending in the United States, primarily on our Frenchman, Republican and Lay Creek projects, is expected to be approximately $8.5 million.

Of the $28.5 million described above, we plan to fund the $20 million estimated for the Australian capital expenditures using our Australian bank senior credit facility described below. Of the remaining $8.5 million in planned United States expenditures, we have determined approximately $6.0 million is discretionary and will be expended only if we obtain additional capital as described below.

We anticipate funding operations and capital expenditures in Australia and the United States for 2005 using (a) cash on hand at December 31, 2004, (b) net gas revenues, (c) expected proceeds of approximately $20 million ($25.7 million AUD) from long term borrowings under our $150 million AUD (approximately $117 million USD) Australian bank senior credit facility and (d) a commitment from Slough to provide funds for working capital, board-approved capital expenditures and operations through April 2006. Our majority shareholder, Slough, intends to divest all or a portion of its ownership interest in the near term. While Slough has committed to support us with long-term loans or equity contributions through April 2006, we do not know what alternative financing or equity investments will be available from other parties after any divestiture occurs. Any alternative financing we may obtain after Slough's divestiture could have terms less favorable than current terms provided by Slough. See Notes 2 and 4 to the Consolidated Financial Statements. At December 31, 2004, we have $25 million USD available for borrowings under our Australian credit facility. We anticipate having sufficient production history from our Frenchman and Republican project wells by late 2005 to be able to borrow money for further development of these projects. In order to fund discretionary domestic capital expenditures in 2005 in excess of these cash resources, we contemplate that we will require alternative sources of capital. Additional sources of funding may include additional debt financings and asset sales. Upon the sale of interests in our prospective acreage, we generally generate cash to reduce our investment in individual projects. However,

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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.

In February 2005, the Company entered into an agreement with Houlihan Lokey Howard & Zukin Capital, Inc., an unrelated party, to provide financial advisory and investment banking services to the Company in connection with Slough's previously announced intention to divest of its ownership in the Company.

We anticipate funding operations and capital expenditures in Australia and the United States over the long-term using (a) net gas revenues, (b) domestic reserve-based debt financing and (c) other debt or equity instruments. We anticipate that our Australian gas sales will increase significantly by 2007, under existing long-term sales contracts, and will provide significant amounts of cash for Australian operating and capital expenditures along with servicing our debt. In the event sufficient long-term operating and capital funding cannot be obtained, we will be required to curtail planned expenditures and may have to sell additional acreage and/or relinquish acreage.

Year Ended December 31, 2003

During 2003, we used $6.6 million of cash in operating activities and invested $25.8 million in capital expenditures and $7.7 million in the repurchase of a royalty interest in the Comet Ridge project. We received proceeds of $3.2 million from the sale of oil and gas assets. Our operating activities and capital investments were funded with $38.5 million in net proceeds from debt financings.

Debt financing during 2003 consisted of approximately $68 million received from Slough Trading Estates Limited ("STEL"). This financing, as discussed in Note 2 to the Consolidated Financial Statements, was primarily used for continued development of the Comet Ridge project and exploration of acreage within ATP 526. In addition, the borrowing from STEL allowed us to retire TCW Asset Management Company ("TCW") debt of approximately $22 million, purchase the $7.7 million royalty interest held by TCW and repay $4.7 million in short term loans from Slough Estates USA Inc. ("Slough"). See Note 4 to the Consolidated Financial Statements. During 2003, we repaid with funds borrowed from STEL the $1.9 million debt associated with a drilling rig currently being used in Australia.

At December 31, 2003, we owed Slough Estates USA Inc. ("Slough") $4 million. The loan, which is due in April 2006, bears interest at LIBOR (1.178% as of December 31, 2003) plus 3.5%.

The table below provides a detailed analysis of our capital expenditures of $33.5 million during the year 2003.

Capital Expenditures Activity in 2003
(in thousands)

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Included within 2003 capital spending was $699,000 of capitalized interest expense associated with our Australian and domestic properties.

During the year ended December 31, 2003, we received proceeds from asset sales of $3.2 million associated with the sale of a 75% interest in our Stateline prospect located in western Nebraska.

RESULTS OF OPERATIONS

Comparison of Year Ended December 31, 2004 and Year Ended December 31, 2003

We incurred a net loss of $15.3 million in 2004 compared to a net loss of $15.4 million in 2003. A $2.2 million increase in gas revenues was offset by increases in (i) legal expenses attributed to litigation, (ii) operating costs, and (iii) interest expense associated with increased debt used to fund our exploratory and development drilling programs in both Australia and the United States. The table below provides a comparison of operations. The table is intended to provide a comparative review of significant operational items and, 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.

⁽¹⁾

Average operating costs per Mcf for the year is for our sole producing property. For a more meaningful comparison of operating costs per Mcf, significant operating costs associated with non-producing properties in the dewatering stage have been excluded.

Revenues and Volumes

The 36% increase in our operating revenues was primarily attributed to a 14% increase in gas volumes sold and a 19% increase in average gas prices from our Australian Comet Ridge project. During the first half of 2004, all of our Australian Comet Ridge gas production was sold under a five-year contract with Energex

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Retail Pty Ltd ("Energex"), an unaffiliated customer. During the last half of 2004, we sold our gas to four purchasers, including Energex, under various short and long term contracts. Favorable foreign currency exchange rates and increases to prices received under our gas contracts contributed to the average gas price increase.

We had nominal gas production and gas sales from our United States oil and gas properties.

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 relating to the Comet Ridge project includes gas balancing provisions to govern production allocations in this situation. If excess takes of natural gas exceed our remaining proved reserves for the property, we record a natural gas imbalance in other liabilities. As of December 31, 2004, we had taken and sold more than our share of natural gas volumes produced from the Comet Ridge project, and we were overproduced by approximately 1,607 MMcf (net of royalties). Based on the December 31, 2004 average sales price of $1.88 per Mcf, this overproduction represents approximately $3.0 million in gas revenues. No liability has been recorded for the excess volumes taken as they did not exceed our share of remaining proved reserves. Under the terms of the gas balancing agreement, we may be required to reduce the monthly volumes we sell by up to 50% of our entitled share of sales, to enable underproduced parties to sell more than their entitled share of the gas sales and cure the imbalance.

Expenses

Australia operating expenses increased by 37% in 2004 primarily due to the increased production levels, workover expenditures, and transportation costs incurred to move gas to contract delivery points, and changes in foreign currency exchange rates. Average operating costs per Mcf sold in Australia increased from $0.88 per Mcf to $1.06 per Mcf, an increase of 20%. Operating costs averaged $1.36 per Mcf for the first half of 2004 due to lower sales volumes. A significant increase in sales volumes in the last half of 2004 increased our utilization of our compressor facilities, and reduced our average operating costs for the last half of 2004 to $0.92 per Mcf. In December 2003, we significantly increased our Comet Ridge compression capacity and associated costs in preparation for future sales increases.

Depletion expense for our Australian project increased 23% in 2004 primarily due to higher sales volumes and an increase of $0.02, or 6%, in the average depletion rate per unit produced and sold. Higher finding costs for reserves added was the principal factor increasing the depletion rate.

Domestic operating costs were largely attributable to the Lay Creek coalseam methane project where the initial wells are in the dewatering phase. Operating costs in the Powder River Basin, our sole domestic producing property in 2004 and 2003, averaged approximately $2.65 per Mcf, a decrease of 1% compared to the same period in 2003.

General and administrative expenses increased by $2.1 million or 37% in 2004 primarily due to legal and consulting costs for the Tri-Star litigation. We incurred $2.8 million in litigation related legal fees in 2004, an increase of approximately $1.4 million over 2003. With the Tri-Star litigation settlement closing in December 2004, we expect litigation legal fees and consulting expenses to decrease by more than $2 million in 2005.

Interest expense increased by approximately $2.3 million in 2004 primarily due to increased borrowings and higher loan balances. We were able to reduce the effective interest rate on the debt used to fund our Australian Comet Ridge project when we entered into a new bank senior credit facility which was used to refinance TOGA's debt owed to Slough and to fund development of the Comet Ridge project.

Income Taxes

We incurred net losses of $15.3 million, $15.4 million, and $4.8 million in 2004, 2003, and 2002, respectively. SFAS No. 109 "Accounting for Income Taxes" requires that a valuation allowance be provided

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if it is more likely than not that some portion or all of a deferred tax asset will not be realized. Our ability to realize the benefit of our deferred tax asset will depend on the generation of future taxable income through profitable operations and the expansion of our exploration and development activities. The market and capital risks associated with achieving the above requirements are considerable, resulting in our conclusion that a full valuation allowance be provided. Accordingly, we did not recognize any income tax benefit in our Consolidated Statements of Operations for these years.

Comparison of Year Ended December 31, 2003 and Year Ended December 31, 2002

The Company incurred a net loss of $15.4 million in 2003 compared to a net loss of $4.8 million in 2002. The increase in the loss is principally attributable to the write-off of deferred loan costs, higher debt service costs, an impairment of the carrying value of the Company's U.S. oil and gas properties and higher operating costs. The increase in the higher operating costs was partially offset by a favorable currency exchange gain. The table below provides a comparison of operations. The table is intended to provide a comparative review of significant operational items and, 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.

⁽¹⁾

Average operating costs per Mcf for the year ended December 31, 2003 is for the Company's sole producing property in 2003. For a more meaningful comparison of operating costs per Mcf, significant operating costs associated with non-producing properties sold and properties in the dewatering stage have been excluded.

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Revenues and Volumes

The 27% increase in our operating revenues was primarily due to increased gas production and higher gas prices received from our Australian Comet Ridge project. Australian revenues increased 38% due to a 15% increase in gas volumes sold and a 20% increase in average gas prices. Favorable foreign currency exchange rates were the principal factors contributing to the average gas price increase. Our Australian gas sales contracts in 2003 were long-term fixed contracts with yearly adjustments for inflation.

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 relating to the Comet Ridge project includes gas balancing provisions to govern production allocations in this situation. If any excess takes of natural gas exceed its remaining proved reserves for the property, we record a natural gas imbalance in other liabilities. As of December 31, 2003, we had taken and sold more than our share of natural gas volumes produced from the Comet Ridge project, and we were overproduced by approximately 1,752 MMcf (net of royalties). Based on the December 31, 2003 average sales price of $1.78 per Mcf, this overproduction represents approximately $3.1 million in gas revenues. No liability was recorded for the excess volumes taken as they did not exceed our share of remaining proved reserves. Under the terms of the gas balancing agreement, we may be required to reduce the monthly volumes we sell by up to 50% of our entitled share of sales, to enable underproduced parties to sell more than their entitled share of the gas sales and cure the imbalance.

Domestic gas sales decreased significantly due to the sale of substantially all of our domestic producing properties in May 2002.

Expenses and Foreign Exchange Gains/Losses

Australia operating expenses increased by 41% in 2003 primarily due to an increase in the number of wells drilled and producing, an increase in the Company's ownership in the Comet Ridge project in mid-2002, and changes in foreign currency exchange rates. The average operating costs per Mcf sold in Australia increased from $0.72 per Mcf to $0.88 per Mcf, an increase of 22%. The rise in operating costs, principally in the Comet Ridge Fairview field, was due to higher field costs caused by the increase in the number of wells to be serviced and higher compressor costs.

Depletion expense for our Australian project increased 26% in 2003 primarily due to higher sales volumes and an increase in the average depletion rate per unit produced and sold. Higher finding costs for reserves added was the principal factor increasing the depletion rate.

The impairment expense of approximately $2.7 million was attributed largely to unsuccessful exploration on the Nine Mile prospect.

Domestic operating costs were largely attributable to the Lay Creek coalseam methane project where the initial ten wells were in the dewatering phase. Operating costs in the Powder River Basin, the Company's sole domestic producing property, averaged approximately $2.69 per Mcf.

General and administrative expenses increased 15% in 2003 primarily due to higher personnel costs associated with increased activity in Australia resulting from growth of the Comet Ridge project.

Interest expense increased by $2.9 million in 2003 due to increased borrowings and higher loan balances. In the third quarter of 2003, we wrote off approximately $5.1 million in deferred loan costs related to the TCW loan retired on August 15, 2003.

We recovered $924,000 of prepaid drilling costs previously written off in 2001 and 2000. Both the recovery and write-offs are associated with the litigation involving our Australian properties. See Note 12 to the accompanying Consolidated Financial Statements.

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The foreign currency exchange gain, recognized in accordance with Statement of Financial Accounting Standard ("SFAS") No. 52, "Foreign Currency Translation" ("SFAS No. 52"), approximated $2.6 million in 2003. This gain was principally attributable to intercompany debt TOGA owed Tipperary Corporation prior to August 15, 2003. The non-permanent portion of this intercompany debt was substantially reduced on August 15, 2003.

ITEM 7A. 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 and interest rates and commodity prices. We do not use financial instruments to any degree to manage foreign currency, interest rate and commodity risks and do not hold or issue financial instruments to any degree for trading purposes. At December 31, 2004, we were exposed to some market risk with respect to foreign currency, interest rates and natural gas prices; however, management does not believe such risk to be material.

Foreign Currency Risk

TOGA uses the Australian dollar as its functional currency. To the extent that business transactions in Australia are not denominated in the Australian dollar, we are exposed to foreign currency exchange risk. During 2003, we benefited from the non-permanent intercompany debt TOGA owed Tipperary Corporation that was denominated in U.S. dollars, and we recorded a foreign currency gain of $2.6 million related to this intercompany debt. As this non-permanent intercompany debt is now retired, we do not anticipate recording significant foreign currency gains or losses in 2005 due to changes in exchange rates. During 2004, our exchange gain was not significant. TOGA does expect to participate in some U.S. dollar transactions, but does not anticipate such transactions will result in a significant foreign currency risk. During 2003 and 2004, we experienced significant increases in our accumulated translation adjustment, the oil and gas properties accounts, and the standardized measure of proved reserve value due to the strengthening of the Australian dollar as compared to the U.S. dollar. We may experience significant changes in these accounts and the standardized measure during 2005 and in future years if exchange rates are volatile. The majority of our revenues, operating expenses and general and administrative expenses in Australia are incurred in Australian dollars. During 2003 and 2004, our revenues and expenses increased as a result of the strength of the Australian dollar. We expect our financial results will be impacted by exchange rate volatility, but we do not expect a significant effect on future earnings as a result of this volatility.

Interest Rate Risk

We currently have a significant amount of outstanding debt, and we are exposed to risk resulting from changes in interest rates. While a portion of our current debt is under long-term fixed interest rate agreements, our Australian debt facility has a floating rate. We are at risk that rates could increase and costs required to refinance the debt may be prohibitive. At current debt levels, a 1% change in interest rates will result in a cost or benefit to us of approximately $1.0 million per year.

Commodity Price Risk

Virtually all of our current sales revenues consist of natural gas sold in eastern Australia. The eastern Australian gas market is primarily composed of long-term fixed price contracts with adjustments made for the rate of inflation which minimizes our commodity price risk. Although not anticipated, we may be required to recognize a non-cash ceiling test impairment, as described in our Critical Accounting Polices found in Item 7 of this Form 10-K, of our Australian properties if more costs are added to the full cost pool than are supported by additional gas reserves or if the Australian dollar weakens significantly.

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We have in the past and plan in the future to sell significant quantities of gas and oil in the United States market. If we do sell significant quantities of gas and oil in the United States, we may be exposed to price volatility that could affect our revenues and the carrying value of our U.S. oil and gas properties.

ITEM 8. FINANCIAL STATEMENTS

The Company's financial statements and related audit report appear on pages 29 through 61 in this annual report:

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Tipperary Corporation:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of stockholders' equity and of cash flows present fairly, in all material respects, the financial position of Tipperary Corporation and its subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 5 to the Consolidated Financial Statements, the Company changed its method of accounting for asset retirement costs effective January 1, 2003.

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TIPPERARY CORPORATION AND SUBSIDIARIES

Consolidated Balance Sheets

($ in thousands except per share data)