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ITEM 8. FINANCIAL STATEMENTS

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)

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 $38,853,000 based on the closing price of $2.60 per share as of June 30, 2003.

Shares of the registrant's Common Stock outstanding as of March 14, 2004: 39,321,489 shares.

Documents incorporated by reference and the Part of the Form 10-K into which the document is incorporated: Definitive Proxy Statement for the 2004 Annual Meeting of Shareholders to be filed within 120 days after the year ended December 31, 2003 (Part III).

PART I

ITEMS 1 AND 2. DESCRIPTION OF BUSINESS AND PROPERTIES

GENERAL

Tipperary Corporation and its subsidiaries (the "Company") are principally engaged in the exploration for, and development and production of, natural gas. The Company is primarily focused on coalseam gas properties, with its major producing property located in Queensland, Australia. The Company also holds exploration permits in Queensland and is involved in coalseam gas and conventional exploration in the United States with three projects in Colorado and one project in Nebraska. The Company seeks to increase its reserves through exploration and development projects but occasionally may do so through the acquisition of producing properties as well.

The Company was organized as a Texas corporation in January 1967. The Company maintains its principal executive offices at 633 Seventeenth Street, Suite 1550, Denver, Colorado 80202. In addition, the Company leases office space at 952 Echo Lane, Suite 375, Houston, Texas 77024 and at Level 20, 307 Queen Street, Brisbane, Queensland 4000, Australia.

All of the Company's 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. The Company also maintains an internet site at www.tipperarycorp.com providing access to its recent public filings. The Company's website is not part of this annual report on Form 10-K.

The following discussion 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, the Company undertakes 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 the Company's production or sales volumes;



•

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



•

competing supplies of gas in Australia;



•

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



•

future production and development costs;



•

the ability of the Company to obtain financing for its 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



•

ability to obtain and continue gas sales contracts in Australia.

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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

The Company's activities in Australia are conducted substantially through its 90%-owned Australian subsidiary, Tipperary Oil & Gas (Australia) Pty Ltd ("TOGA"). Most of the Company's activity is focused on the Comet Ridge project located in the Bowen Basin in the state of Queensland.

In Queensland, oil and gas exploration is conducted under an Authority to Prospect ("ATP"). 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 ("PL"). It provides the lessee with the ability to conduct additional exploration, appraisal, development and production activities and sell any produced oil and gas from the lease acreage for a stated term.

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 Queensland DNRM 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. Negotiatied expenditure requirements vary from year to year.

⁽³⁾

Petroleum Leases annual nominal capital expenditures for each Petroleum Lease of about $275,000. The expenditure requirements are reduced by royalties paid on gas sales. In 2003, the Company paid royalties on PL 91 and 92 in excess of the expenditure requirements.

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⁽⁴⁾

The Company is in correspondence with the Queensland DNRM and is not certain of its work commitment as of March 15, 2004. The ATP 526 expenditure requirements will be $3 million or less for a drilling program and $2 million or less for a seismic program. The ATP 653 expenditure requirements will be $3 million or less for a drilling program.

⁽⁵⁾

The term on ATP 554 has expired; however, the Queensland DNRM has allowed the ATP holders a limited time to pursue investment from other parties. The associated acreage may be relinquished at any time. The Company does not expect to spend any significant amount on this project prior to obtaining more industry participation.

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

Comet Ridge Operations Review

The Company drilled 27 wells on the Comet Ridge project during 2003. Of the wells drilled in 2003, eight wells are considered exploratory wells. The remaining wells drilled are in development locations and are expected to contribute to gas sales volumes after the gathering system is expanded to include these wells. The 2003 drilling was substantially funded under a $25 million borrowing facility entered into in March 2003 with Slough Trading Estates Limited ("STEL"), a United Kingdom company which is the parent company of the Company's majority shareholder, Slough Estates USA Inc. ("Slough"). See Note 2 to the Consolidated Financial Statements.

United States

The Company's assets in the United States consist primarily of exploration leasehold acreage in Colorado and Nebraska.

The Company holds a 50% working interest in the Lay Creek coalseam gas project in Moffat County, Colorado. The project includes various leasehold interests covering over 82,000 gross acres. Koch Exploration Company ("Koch"), an unaffiliated third party, holds the remaining 50% working interest and operates the project. 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. During 2001 and 2002, the Company drilled and completed

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ten wells that constitute two five-well pilot programs. 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. The Company and Koch drilled four additional pilot wells during the period from December 2003 through February 2004 at an expected cost to the Company of $1.0 million offsetting one of the five-well pilot programs.

In February 2002, the Company sold a 60% interest in the Nine Mile Prospect, a 49,000 acre conventional oil and gas exploration prospect 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. In September 2002, the Company announced the completion and initial testing of the first well on the prospect. Since then the Company has become the operator of the project, two dry holes have been drilled and the production rates of the initial well have proved to be uneconomic. The Company recorded a domestic full cost ceiling test impairment during 2003 of approximately $2.6 million. In exchange for the Company's assumption of Elm Ridge's obligation for plugging and abandonment costs, Elm Ridge has assigned its interest in portions of the Nine Mile prospect to the Company. Currently, the Company is evaluating the Nine Mile prospect and is seeking industry partners before resuming any further exploratory work.

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 comprised of approximately 280,000 gross acres in eastern Colorado for $4.8 million in cash. The Company retained the remaining 25% to 20% interests in the acreage. Kerr-McGee serves as operator of these project areas. In the second quarter of 2003, the first well was drilled on the Frenchman prospect and during the third quarter of 2003, four additional wells were drilled of which two were completed and two were plugged and abandoned. Limited gas production testing has been conducted and drilling and seismic data are still being evaluated. The 2004 drilling program includes the drilling of two wells at an expected cost to the Company of $420,000 on the Frenchman prospect in which Kerr-McGee has elected not to participate. Should the Company complete these wells as commercial producers, it will earn 100% of offsetting drill sites around these well bores. The Company expects to drill as many as ten wells on the Republican prospect at a cost to the Company of approximately $800,000.

In July and October 2003, the Company sold to an unaffiliated third party a 75% interest in the Stateline prospect in western Nebraska for $3.2 million in cash. The Company retained the remaining 25% interest in the acreage. Total gross acreage sold in the project was approximately 117,000 acres. The purchaser will serve as operator of the project. In accordance with the full cost accounting rules, the Company recorded the proceeds as a reduction of its domestic full cost pool, with no gain recognized. In the first quarter of 2004, seismic operations are being conducted at a cost to the Company of approximately $100,000. Further seismic operations and exploratory drilling may be conducted if the results of the seismic testing are encouraging.

During late 2003, the Company acquired leasehold acreage in western Nebraska totaling approximately 51,000 gross acres, which is referred to as the Sand Hill prospect. This acreage is located in the vicinity of the Company's Frenchman, Republican and Stateline prospects. The Company is actively marketing the Sand Hill prospect and plans to sell an interest to recover its investment and retain an interest in this acreage.

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PRODUCING WELLS AND ACREAGE

The following table sets forth information with respect to the Company's producing wells and acreage as of December 31, 2003:

⁽¹⁾

The acreage reported in this table includes only that which is covered by a Petroleum Lease. The Company also holds, either directly or indirectly, ATPs as previously disclosed in the Exploratory and Development Acreage Summary—Australia. Gross producing gas wells includes 20 (13.90 net) wells that were drilled, completed and production tested but have not yet been connected to the gathering system of the Comet Ridge project.

⁽²⁾

The Company's domestic producing wells currently are being pilot tested to determine whether they are economic and accordingly, no proved reserves are recognized. The Company's 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 the Company. 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 Operation."

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DRILLING ACTIVITIES

Information concerning the number of gross and net wells drilled and completed by the Company during 2003, 2002 and 2001 is as follows:

⁽¹⁾

During 2003, the Company drilled on ATP acreage nine (6.87 net) exploratory wells that were not completed at December 31, 2003 and have therefore not been included in the table.

⁽²⁾

During 2001, 2002 and 2003, the Company drilled two (1.39 net), one (.69 net) and 15 (10.43 net) development wells, respectively, that were completed but not yet connected to the gathering system. These 18 wells are included in the table.

⁽³⁾

Two (1.00 net) development wells drilled during 2003, six (3.00 net) development wells drilled during 2002 and two (1.00 net) exploratory wells drilled during 2001 are coalseam gas wells in the Lay Creek project and will require further dewatering in order to determine whether they are economically viable.

⁽⁴⁾

Two exploratory coalseam gas wells previously reported as productive have been reclassified as dry holes. Further testing indicated the wells would not produce commercial quantities of gas.

⁽⁵⁾

Two (.33 net) development wells drilled during 2001 were in the West Buna field in Texas. The West Buna field was sold in 2002. Two (.40 net) development wells drilled during 2001 were in the Hanna Basin project in Wyoming and were previously reported as productive. These wells have been reclassified as dry holes as further testing indicated the wells would not produce commercial quantities of gas. The Hanna Basin project was sold in 2003. The remaining 11 (.16 net) development wells were drilled in the Powder River basin in Wyoming.

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PRODUCTION

The following table summarizes information regarding the Company's 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 2003, all gas sales in Australia were pursuant to two contracts with ENERGEX Retail Pty Ltd ("ENERGEX"), an unaffiliated gas distributor owned by the State of Queensland. The first contract had delivery requirements of up to approximately 5,300 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 through June 2005. 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 approximately 25,000 Mcf of gas per day net to the Company's interests, for 13 years beginning in May 2007. Origin Energy Limited is a large Australian integrated energy company which, through subsidiaries, owns nearly 24% of the Comet Ridge project.

Effective December 31, 2003, the Company extended until March 31, 2004, a gas supply agreement with Queensland Fertilizer Assets Limited ("QFAL") to supply 210 Bcf of gas over a 20-year period beginning in mid 2006 to a fertilizer plant QFAL is proposing to construct in southeastern Queensland. Prior to March 31, 2004, QFAL is required to obtain commitments to finance construction of the fertilizer plant, or the Company will be released from its gas supply commitment unless the agreement is extended. The Company expects to further extend this agreement to September 30, 2004. The Company believes it has reasonable certainty, based upon the gas market in eastern Australia, that its future gas production contracted to be sold to QFAL can be sold in the market in the event it is not sold to QFAL.

The Company believes 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.

United States

In the United States, the Company has sold its oil and gas production to several purchasers during the past several years, generally under short-term contracts. During 2003, the Company did not have material domestic oil or gas sales. In 2002, the Company had domestic sales in excess of 10% of total U.S. revenues to BP America Production Co. and Smith Production Inc. of 54% and 40%, respectively.

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PRICING

Australia

In Australia, the Company's sales to ENERGEX during 2003 were under two fixed-price contracts in Australian dollars which are adjusted for inflation annually. The average U.S. dollar equivalent price during 2003 for the 5,300 Mcf per day delivered under the first contract was $1.43 per Mcf. Deliveries under the second contract averaged 7,800 Mcf per day during 2003 at a U.S. dollar equivalent price of $1.50 per Mcf.

The Company's contract with OERL calls for a U.S. dollar equivalent price higher than the Company's existing Energex contract. The contract term is from 2007 through 2020. The OERL contract revenues will also be paid in Australian dollars and will be adjusted for inflation annually.

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. The Company's domestic oil and gas sales have been through contracts whereby the oil and gas is sold at the wellhead.

The Company has occasionally used derivatives to hedge risks associated with the volatility of oil and gas prices in the United States. None of the Company's production has been hedged since 2000. See the discussion of hedging activities in Note 1 to the Consolidated Financial Statements.

RISK FACTORS

The Company's operations are subject to a variety of material risks, including the following:

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

Although our gas revenues from our sole producing gas property in Australia have increased significantly on a year by year basis over the past several years, our volumes sold in 2003 did not increase significantly compared to 2002. We are currently pursuing long-term contracts which commence predominately in 2006 and 2007. We have the capability to significantly increase our current gas sales in Australia and are discussing near-term contracts with several parties. In order for us to reduce our operating losses in the near term, we must secure contracts that require significant near-term sales.

The eastern Australian gas market is currently developing.

If, as we develop and expand production of our Australian gas reserves, the eastern Australian market for gas does not also develop and grow, we may be able to produce more gas than available markets can absorb. This could cause us to not sell gas in significant quantities as well as cause natural gas prices to significantly decrease, which would negatively impact our results of operations and financial condition. Unlike the United States, the market for natural gas in eastern Australia is primarily based on commercial and industrial use. Additionally, while infrastructure is growing rapidly, we do not presently have a physical connection to sell gas in New South Wales and South Australia. Although the Company expects to sell gas into New South Wales and South Australia in the future, there can be no assurance that physical connections will be built or of market share there.

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

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

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Guinea's southern highlands fields has experienced varying degrees of interest within the industry for several years. 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 earnings and financial condition.

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;



•

estimating amounts of gas markets can absorb;



•

projecting future rates of production, and



•

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.

Proved Reserves; Ceiling Test.    Changes in economic and operating conditions, such as a deterioration of gas prices, could result in our recording a non-cash charge to earnings as of the end of a quarter or year. We have incurred impairment charges in the past and may do so in the future. Our proved reserve estimates are based upon our analysis of our oil and gas properties and are subject to SEC rules. We periodically review the carrying value of our oil and gas properties under the full cost accounting rules of the SEC. Under these rules, capitalized costs of oil and gas properties on a country-by-country basis may not exceed the present value of estimated future net cash flows from proved reserves, discounted at 10%, plus the cost of unevaluated properties as adjusted for related tax effects. At the end of each quarter, the test is applied using unescalated prices in effect at the applicable time and may result in an impairment if the "ceiling" is exceeded, even if prices decline for only a short period of time.

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 rely 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.

Failure to pay by our only customer could negatively affect our results of operations.

All of our current Australia natural gas sales are made to one purchaser under one five-year gas supply contract. Loss of revenue from this major customer due to nonpayment could have a negative impact on our results of operations.

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;

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•

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 performance. Further, in the event of a dispute in Australia that does not arise under the joint operating agreement for 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.

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 Minister for Natural Resources and Mines. Each ATP requires the expenditure of a set amount of exploration costs, and is 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.

We may be negatively impacted by the currency exchange rate between United States and Australia since we receive significant revenues from gas sales in 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, our reported U.S. revenues are impacted by foreign currency fluctuations. In addition, we may experience fluctuation in our accumulated translation adjustment and oil and gas property accounts due to currency fluctuations. Foreign revenues are also subject to special risks that may disrupt markets, including the risk of war, civil disturbances, embargo and government activities.

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 three 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. Our operating losses are likely to continue until we attain significantly greater natural gas sales volumes. These losses can be expected to deplete our capital and require us to seek additional financing. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations".

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

In the near term, the Company expects to enter into a binding agreement with a consortium of Australian banks for a loan of $150 million AUD (approximately $112 million USD at current exchange rates) to refinance existing debt and further develop the Comet Ridge project. The debt will have a variable interest rate and 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. See "Item 7A. Quantitative and Quantitative Disclosure About Market Risk."

We have 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 annual inflation adjustments. This mitigates commodity price risk.

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We may not be able to raise adequate financing to further develop our natural gas properties.

There is currently insufficient cash flow from operations to support our overhead and other projected cash needs during 2004. However, in the near term, the Company expects to enter into an agreement to borrow up to $150 million Australian dollars (approximately $112 million USD) from a group of banks to refinance $90 million AUD in existing debt and to fund our operating and capital needs in Australia for the next few years. We also have obtained written commitments from Slough, our majority shareholder, that Slough will provide funds for working capital, board-approved capital expenditures and operations. We expect that we will explore other financing alternatives, including additional debt financing, further sales of common stock and asset sales. However, we may not be able to obtain additional financing required to fund our proposed business plan beyond 2006. To the extent additional financing is obtained, it may not be on terms beneficial to our stockholders.

We may require future funding from our majority stockholder the terms of which may be disadvantageous to us.

For the past several years a significant source of liquidity as well as long term financing has been from debt and equity financing provided by Slough and its affiliates. We may need to seek additional funding from Slough, although we cannot give any assurance that it will be willing to make additional investments in the Company beyond these investments committed to in our current agreements with Slough. Because alternative financing may not be available, additional stock purchases or loans of additional funds from Slough could be on terms that are not advantageous to our other stockholders.

We must successfully develop existing reserves and acquire or find additional reserves of gas or oil in order to continue long-term production.

Our future production of gas is highly dependent upon our level of success in developing reserves we have discovered and in acquiring or finding additional reserves. The rate of production from our gas properties generally decreases as reserves are depleted. Because we must increase production to become profitable, it is very important for us to continue to develop gas reserves in Australia.

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

As the non-operating owner of working interests in the United States, we do not have the right to direct or control with certainty 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 may be negatively affected.

We are in litigation with the former operator of our major Australian property.

We and certain other interest owners in the Comet Ridge project in Queensland, Australia have brought a lawsuit against the former operator on the project for, among other claims, breach of the operating agreement. The lawsuit has been pending for several years. The outcome of any litigation is difficult to predict. In March 2002, we became operator of the Comet Ridge project as a result of an injunction issued by the court. We will remain operator at least through the conclusion of a trial on the merits as the former

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operator has exhausted all appeals. If successful at trial, we will continue as operator. However, the outcome of this litigation is uncertain. See Item 3. Legal Proceedings.

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 hurt the market price of our common stock. As of December 31, 2003, we had 39,221,489 shares of common stock outstanding. Potential future sales of our common stock include 27,290,022 shares beneficially held by our officers, directors and principal stockholders, comprised of common stock held and options and warrants, representing 70% 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 affect the volatility of 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 69% 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.

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 dilution to the value of their shares. As of December 31, 2003, we had warrants and options outstanding to purchase 3,598,400 shares of our common stock at a weighted average exercise price of $2.46 representing 8.40% 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.

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.

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

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environment. Even if our exploration activities discover gas or oil reserves, we may not be able to produce quantities sufficient to justify the cost of exploring for and developing reserves. 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 transportation and market risks we face in Australia. The occurrence of a significant event that is not fully insured could negatively impact our results of operations and financial condition.

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 consistent with industry practices prior to acquiring any gas and oil property, reviews of this type are inherently incomplete. It generally 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 projects do not include the acquisition of developed properties, future acquisitions may have a negative effect upon our operating results.

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. The Company entered into an employment agreement with Mr. Bradshaw on September 18, 2001. This agreement automatically renews every two years unless terminated under the 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.

Uncertainty due to terrorist attacks and war may adversely impact financial results and condition, our ability to raise capital and our future growth.

The attacks that occurred in New York, Pennsylvania and Washington, D.C. on September 11, 2001 and future attacks and war risks, may adversely impact our results of operation, financial condition, ability to raise capital or future growth. Uncertainty surrounding retaliatory military strikes or a sustained military campaign may impact our operations in unpredictable ways, including general disruptions to commerce and the possibility that oil and gas infrastructure facilities, such as refineries, pipelines and storage structures, could be direct targets of, or indirect casualties of, an act of terror or war. In addition, war or the risk of war may also have an adverse effect on the economy. A lower level of economic activity could result in a decline in the consumption of oil and gas which will negatively affect our revenues, financial position and future growth. Furthermore, instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.

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

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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.

PROVED OIL AND GAS RESERVES

Supplementary information concerning the Company's estimated proved oil and gas reserves and discounted future net cash flows applicable thereto is included in Note 14 to the Company's Consolidated Financial Statements herein.

The Company did not file any estimates or reserve reports of the Company's proved domestic net oil or gas reserves with any governmental authority or agency other than the Securities and Exchange Commission during the year ended December 31, 2003.

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 condition requiring compliance with the Australian Petroleum Production and Exploration Association Code of Practice. The Company has incurred costs of approximately $146,000, $35,000 and $10,000 in 2003, 2002 and 2001, respectively, in Australia to comply with environmental regulations. In the fourth quarter of 2003, the Queensland government notified the Company that exploration and production of gas from under national park lands would be limited to using surface facilities located outside the parks. If gas reserves are discovered under park lands, they would be recovered using directional drilling from drill sites adjacent to park lands. Directional drilling is used to produce some coalseam and conventional gas in the US. 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 per mcf sold. Three of the Company's productive wells and one ATP 526 exploration well were previously permitted on park lands. Under current government policy, the four wells will be plugged and abandoned, and the surface area reclaimed at an estimated cost to the Company of $100,000. The Company expects to recover these wells' reserves using directional drilling. The amount of 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 the Company will not incur significant costs in the future to comply with these laws and regulations.

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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. The Company cannot currently ascertain the impact of the Regime, but believes it should benefit the Company.

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.    The Company's business activities are subject to federal, state and local environmental laws and regulations. Compliance with these regulations increases the Company's 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. The Company has incurred costs of approximately $102,000, $51,000 and $25,000 in 2003, 2002 and 2001, respectively, in the United States to comply with environmental regulations. The Company will continue to monitor its environmental compliance. There can be no assurance that environmental laws and regulations will not become more stringent in the future or that the Company will not incur significant costs in the future to comply with these laws and regulations.

EMPLOYEES

At December 31, 2003, the Company employed 13 persons in the United States and 43 persons in Australia on a full-time basis, including its officers. None of the Company's employees are represented by unions. The Company considers its relationship with its employees to be excellent.

ITEM 3. LEGAL PROCEEDINGS

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,

15

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, and TOGA did succeed Tri-Star as operator on March 22, 2002. All available appeals have been exhausted. Therefore, 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. The Eighth District Court of Appeals affirmed the action of the District Court, and Tri-Star has filed a Petition for Review and a Petition for Writ of Mandamus in the Supreme Court of Texas. The Supreme Court has asked for briefing on the merits, without granting review of either Petition, and the Company has filed its responses. The Supreme Court has discretion to either hear, or refuse to hear, the appeals, and no decision has yet been announced. Although pre-trial discovery is proceeding, the pending appeals continue to delay the trial on the merits. If all appeals are resolved, the case is set for trial beginning the week of September 27, 2004.

In August 2003, the District Court heard the Company's Motion to Compel Compliance with Amended Writ of Temporary Injunction. On October 1, 2003, the Court signed an Order finding that Tri-Star willfully disobeyed the Injunction, ordering Tri-Star to cooperate with the Operator and, among other things, to execute a power of attorney to allow the Company to deal directly with the Department of Natural Resources and Mines in Queensland, and the surface owners, on matters pertaining to the Comet Ridge project. Tri-Star filed objections to the power of attorney. In January 2004, the Court conducted a show cause hearing to determine whether sanctions for Tri-Star's past violations of the Injunction, and conditional sanctions to deter future violations, should be imposed and heard Tri-Star's motion to increase the amount of the bond securing the injunction from $500,000 to $1.0 million and objections to the power of attorney. On March 8, 2004, the Court ruled that the bond will not be increased and denied Tri-Star's objections to the power of attorney. The Court has not yet ruled on sanctions against Tri-Star.

Prior to taking over operations, the Company and other plaintiffs paid $1.3 million in disputed joint interest billings to the Registry of the Court, for future payment to Tri-Star for billings held to be proper, or future repayment to plaintiffs for billings held to be improper. In 2002, Tri-Star effectively collected the disputed billings by withholding $1.3 million in unused drilling funds advanced by the plaintiffs to Tri-Star. In December 2003, the parties agreed that the Registry monies should be released to the plaintiffs, although the validity of the disputed billings remains in dispute and a matter of the litigation. In December 2003, the Company received its $1.3 million share of Registry funds, including interest. Upon receipt of the funds, the Company recorded recovery of prepaid drilling costs of $924,000, interest income of $107,000, court fees of $11,000 and a liability of $186,000.

If the Court agrees that amounts billed to the Company were improper, then upon recovery from the defendants, 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.

The Company will claim substantial 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.

The Company may be involved in various routine disputes in the ordinary course of business. The Company believes that the final resolution of such currently pending or threatened litigation is not likely to have a material adverse effect on the Company's financial position or results of operations.

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

The Company's common stock is listed and has been trading on the American Stock Exchange since April 1992. As of March 9, 2004, there were approximately 1,700 holders of record of the Company's common stock. The table below sets forth the high and low closing prices for the common stock of the Company for the periods indicated:

The Company has not paid any cash dividends on its common stock and does not expect to pay any dividends in the foreseeable future. The Company intends to retain any earnings to provide funds for operations and expansion of its business.

SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

The table below provides certain information as of December 31, 2003 with respect to compensation plans under which equity securities of the Company are authorized for issuance:

At December 31, 2003, the Company had 1,176,900 warrants outstanding with directors, employees and non-employees. From time to time, the Company has offered warrants to directors and employees as an incentive to provide long-term service to the Company. The terms of each warrant are negotiated. Less frequently, the Company has offered warrants to consultants as part of their compensation agreement.

ITEM 6. SELECTED FINANCIAL DATA

The selected consolidated financial information presented below for the years ended September 30, 1999 through December 31, 2003 is derived from the Consolidated Financial Statements of the Company.

Certain reclassifications have been made to prior financial statements to conform with the current presentation. Also, sales and impairments of oil and gas properties and write-offs or deferred loan costs in certain years materially affect the comparability of the financial information presented below. This

17

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 the Company's financial condition and results of operations. This discussion should be read in conjunction with the 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 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, projected or forecasted in the 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.

Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to, changes in the Company's production or sales volumes, worldwide supply and demand which affect commodity prices for oil and gas, competing supplies of gas in Australia, the timing and extent of the Company's 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, the ability of the Company to obtain financing for its 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, 2003, the Company's total proved gas reserves were estimated to be 540 billion cubic feet ("Bcf"), all relating to the Comet Ridge Project in Queensland, Australia. As of December 31, 2003, the Company 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, total discounted future after tax net cash flows were estimated to be $107.6 million as of December 31, 2003, compared to $74.7 million at December 31, 2002. The net increase was due primarily to the addition of proved undeveloped drilling locations resulting from Australian development drilling, the purchase of reserves and the strengthening Australian dollar. Increases in future revenues attributed, in part, to the rise in the value of the Australian dollar were partially offset by similar foreign currency value changes in operating costs and future development costs. The elimination of previously booked domestic reserves relating to the Company's Nine Mile project reduced the domestic discounted future net cash flows to zero, a reduction of approximately $1.9 million.

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The present value of future net cash flows does not purport to be an estimate of the fair market value of the Company's 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.

The Company's gas marketing in eastern Australia is focused currently on obtaining long-term gas sales agreements that provide five to 15 years of firm sales typically starting in 2006 to 2008. The Company's independent engineers estimate that if future gas sales agreements require, Comet Ridge could be developed so as to deliver over the next 15 years (2004 to 2018) approximately 340 Bcf of the 540 Bcf in proved reserves at December 31, 2003. Based on contracts and market conditions at year-end, the discounted net cash flows of $107.6 million for the Company's proved reserves as of December 31, 2003 reflect management's estimates of reasonably certain sales levels. These estimates project sales of 237 Bcf over the next 15 years, with limited sales growth in the near term, escalating to 17 Bcf per annum in 2008. The Company anticipates spending approximately $30 million over the next three years on development drilling and expansion of delivery facilities to increase the Company's annual sales deliverability to 24 Bcf net by 2008.

CRITICAL ACCOUNTING POLICIES

The Company's financial statements are based on the selection and application of significant accounting policies, some of which require management to make estimates and assumptions which affect the reported amounts of assets, liabilities, revenues and expenses and also affect the disclosure of contingent items. The Company believes that the following are some of the more critical judgment areas in the application of its accounting policies that currently affect its 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 the Company records 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 the Company's 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 the Company's 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 the full cost pool as discussed below. If the estimate of proved reserve volumes declines or the estimate of future development costs increases, the DD&A expense the Company records increases, reducing net income. Certain early stage exploratory costs are excluded from costs subject to the DD&A calculation. The Company evaluates these excluded costs quarterly, and the costs are added to the DD&A base if the Company determines the costs will or will not result in commercially productive oil or gas production.

Full Cost Method of Accounting for Oil and Gas Properties

The Company accounts for its oil and gas properties using the full cost method. Under this method, the Company is required to record a permanent impairment provision if the net book value of its 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, the Company 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

20

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 the Company's 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 long-term contracts with fixed prices. However, while there is no 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 the Company to a potential recorded loss in value.

In the event the Company records a reduction in its discounted after-tax future net cash flow from lower estimated reserve quantities, the Company could be required to record a non-cash loss. In addition the Company could record a non-cash loss if costs associated with its domestic exploration projects are added to depletable costs within the domestic full cost pool without sufficient associated oil and gas reserves. While the Company's 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. The Company would however record a lower DD&A expense, since the prior impairment would have reduced the net book value of the full cost pool.

Contingencies

The Company accounts for contingencies in accordance with SFAS No. 5, "Accounting for Contingencies." SFAS No. 5 requires that the Company record an estimated loss from a loss contingency when information available prior to issuance of its 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 the Company to use its judgment and while the Company believes that its accruals for these matters are adequate, if the actual loss from the loss contingency is significantly different than the estimated loss, the results of operations of the Company will be impacted in the period the contingency is resolved.

In the fiscal year ended September 30, 2000 and in 2001, the Company recorded charges to expense of $557,000 and $900,000, respectively, for prepaid drilling costs that the Company had estimated would not be realized as either capital expenditures or cash refunds at that time. These sums were paid to the former operator of the Comet Ridge project in Australia, with whom the Company has been in litigation during the last several years. In the quarter ended September 30, 2002, several months after assuming operations on the Comet Ridge project, the Company recovered $282,000 relating to the prepaid drilling costs previously written off.

Prior to taking over operations, the Company and other plaintiffs paid $1.3 million in disputed joint interest billings to the Registry of the Court, for future payment to Tri-Star for billings held to be proper or future repayment to plaintiffs for billings held to be improper. In 2002, Tri-Star effectively collected the disputed billings by withholding $1.3 million in unused drilling funds advanced by the plaintiffs to Tri-Star. In December 2003, parties agreed that the Registry monies should be released to the plaintiffs, although the validity of the disputed billings remains in dispute and a matter of the litigation. In December 2003 the Company received its $1.3 million share of Registry funds, including interest. Upon receipt of the funds, the Company recorded recovery of prepaid drilling costs of $924,000, interest income of $107,000, court fees of $11,000 and a liability of $186,000.

If the Court agrees that the $1.3 million in disputed billings were improper, then upon recovery from the defendants, the Company would receive $1.2 million and 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. The Company may also record gains or losses upon resolution of the Comet Ridge litigation that are unrelated to these disputed billings.

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RECENT ACCOUNTING PRONOUNCEMENTS

See Note 1 to the Consolidated Financial Statements for recent accounting pronouncements and how the Company anticipates they will impact the Company's financial statements.

LIQUIDITY AND CAPITAL RESOURCES

The Company has used equity and debt financings and sales of producing properties to fund most of its 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 2003, the Company 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. The Company received proceeds of $3.2 million from the sale of oil and gas assets. The Company's operating activities and capital investments were funded with $38.5 million in net proceeds from debt financing.

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 the Company 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, the Company repaid the $1.9 million debt associated with a drilling rig currently being used in Australia with funds borrowed from STEL.

At December 31, 2003, the Company owed Slough Estates USA ("Slough") $4 million. The loan which is due in April 2005 bears an interest rate of LIBOR (1.178% as of December 31, 2003) plus 3.5%.

The Company has various commitments in addition to its long-term debt. The following table summarizes the Company's contractual obligations at December 31, 2003 (in thousands):

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The table below provides an analysis of the Company's capital expenditures of $33.5 million during the year ended December 31, 2003.

Capital Expenditures Activity
(in thousands)

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

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

Exploration and Development Drilling Commitments

The Company's anticipated capital expenditures during 2004 total approximately $22 million. In Australia, the Company expects to incur capital costs of $18 million. Fourteen million dollars would be for exploratory drilling and for gas gathering and water disposal facilities. Four million dollars would be for exploration activities on ATP 653 and ATP 655. Capital spending in the United States, primarily on the Company's Lay Creek, Frenchman and Republican prospects, is expected to be approximately $4 million.

Of the $22 million described above, the Company plans to fund the $18 million estimated for the Australian capital expenditures under the Australian bank facility described below. Of the remaining $4 million in planned expenditures, the Company has determined approximately $3 million is discretionary and will be expended only if the Company obtains additional capital as described below.

The Company anticipates funding operations and capital expenditures in Australia and the United States for 2004 using (a) cash on hand at December 31, 2003, (b) net gas revenues, (c) expected proceeds of approximately $20 million ($27 million Australian) in long term borrowings under an $150 million AUD (approximately $112 million USD) Australian bank credit facility the Company expects to sign in the near term and (d) a commitment from Slough to provide funds for working capital, board-approved capital expenditures and operations. See Note 4 to the Consolidated Financial Statements. In order to fund discretionary domestic capital expenditures in 2004 in excess of these cash resources, the Company contemplates that it will require alternative sources of capital. Additional sources of funding may include additional debt financings and asset sales. With the sale of interests in its prospective acreage, the Company expects to generate cash to reduce its investment in individual projects. However, in the event that sufficient funding cannot be obtained, the Company will be required to curtail planned expenditures and may have to sell additional acreage and/or relinquish acreage.

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Year Ended December 31, 2002

During 2002, the Company used $4.4 million of cash in operating activities and invested cash of $27.4 million in capital expenditures. The Company received proceeds of $10.5 million from the sale of oil and gas assets. The Company's operating activities and capital investments were funded with cash on hand at the beginning of the year of $9.4 million and net proceeds of $13.5 million of debt financing.

Debt financings during 2002 included $10.0 million received from TCW Asset Management Company ("TCW") and $4.0 million received from Slough Estates USA ("Slough"), the Company's largest shareholder. The TCW borrowing was used for continued development of the Comet Ridge project. The $4.0 million received from Slough was used to fund domestic projects and for general corporate purposes. In 2002, the Company made principal payments to Slough of $515,000 on the note payable associated with the drilling rig being used in Australia. Through August 15, 2003, the Company was a party to an amended and restated Credit Agreement with TCW with a principal balance of $22 million, which was used for development of the Comet Ridge project. As set forth in Note 2 to the Consolidated Financial Statements, the Company has repaid this loan.

The table below provides a detailed analysis of capital expenditures of $27.4 million during the year ended December 31, 2002.

Capital Expenditures Activity
(in thousands)

Included within 2002 capital spending was $466,000 of capitalized interest expense associated with the Company's Australian and domestic properties.

Proceeds from asset sales of $10.5 million during 2002 included $4.8 million from the sale of interests in the Frenchman and Republican prospects in Colorado, $4.1 million from the sale of the West Buna properties in Texas, $595,000 received from the sale of a 50% interest in the Nine Mile prospect in Colorado and $1.0 million in reimbursed Lay Creek drilling costs under the terms of a 2001 purchase and sale agreement.

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RESULTS OF OPERATIONS

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 the Company's operating revenues was due principally to increased gas production and higher gas prices received from the Company's 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. The Company's current Australian gas sales contracts are 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. 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 December 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 1,752 MMcf (net of royalties). Based on the December 31, 2003 average sales price of $1.78 per Mcf, this overproduction represents $3.1 million in gas revenues. No liability has been recorded for the excess volumes taken as they do not exceed the Company's share of remaining proved reserves. Under the terms of the 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.

Gas sales in the U.S. decreased significantly due to the sale of substantially all of the Company's U.S. producing properties in May 2002.

Expenses and Foreign Exchange Gains/Losses

Australia operating expenses increased by 41% in 2003 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. Approximately 44% of the per unit operating costs were associated with compressor costs and costs incurred on wells that are dewatering and not selling gas.

Depletion expense for the Australian project increased 26% in 2003 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 are 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 due principally 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, the Company wrote off approximately $5.1 million in deferred loan costs related to the TCW loan retired on August 15, 2003.

The Company 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 the Company's Australian properties. See Note 12 to the accompanying Consolidated Financial Statements.

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Foreign currency exchange gain, recognized in accordance with SFAS No. 52, "Foreign Currency Translation" ("SFAS 52"), approximated $2.6 million in 2003. This gain was principally attributable to intercompany debt TOGA owed the Company prior to August 15, 2003. The non-permanent portion of this intercompany debt was substantially reduced on August 15, 2003, and such reduction is expected to reduce future foreign currency gains and losses.

Comparison of Year Ended December 31, 2002 and Year Ended December 31, 2001

The Company incurred a net loss of $4.8 million in 2002 compared to a net loss of $7.2 million in 2001. The reduced loss in 2002 compared to 2001 resulted primarily from $2.2 million in gains on the sale of two U.S. properties recorded during 2002. The table below is intended to provide a comparative review of significant operational items. Accordingly, nominal differences may exist from the amounts presented in the accompanying Consolidated Financial Statements. Certain prior period amounts may have been reclassified to ensure comparability.

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Revenues and Volumes

While revenues, gas and oil volumes in the U.S. decreased due to the sale of substantially all U.S. producing properties in May 2002, gas volumes sold in Australia increased 58% due to increased gas sales from existing wells and also from new wells drilled and connected to the gathering system during 2002. Gas revenues in Australia increased 67% as a result of the sales volume increase, favorable exchange rate changes and sales price increases during 2002.

Expenses and Foreign Exchange Gains/Losses

Operating expenses in Australia increased 77% along with increased sales volumes. The 5% increase in Australian operating costs per Mcf related to activity at the Comet Ridge Fairview field. The increase consisted of a 4% decrease for field-wide cost efficiencies and a 9% increase related to the Company's acquisition of additional interests in the Fairview field. Cost efficiencies occurred when total field costs increased proportionately less than field sales volumes increased in 2002 over 2001. The acquisitions increased the Company's share of field-wide costs and entitled share of gas sales, but reduced for 2002 the Company's actual gas sales volumes in excess of entitled volumes because of underproduction of the acquired interests. As a result, the Company's share of operating costs increased in 2002 greater than the Company's share of gas sales volumes did. Domestic operating expenses decreased significantly due to the U.S. property sales.

General and administrative expenses for 2002 increased 17% when compared to 2001, primarily due to costs associated with assuming operations of the Comet Ridge project.

In Australia, oil and gas property DD&A expense increased 45% due to increased sales volumes. Other DD&A in Australia increased $119,000 due to depreciation associated with a drilling rig the Company acquired for use on the Comet Ridge project. See Note 6 to the Consolidated Financial Statements.

During 2002, the Company recorded $2.2 million in gains on domestic property sales. The Company also recovered $282,000 in prepaid drilling costs compared to $900,000 for impairment of prepaid drilling costs in 2001. The recovery of prepaid drilling costs was due to funds received from Tri-Star in excess of recorded receivables for unused, prepaid drilling costs. See Note 12 to the Consolidated Financial Statements.

Interest expense increased to $3.1 million from $2.8 million or 7%, primarily due to an increase in long-term debt outstanding for most of 2002.

Foreign currency exchange losses in 2002 were $33,000 compared to a loss of $5,000 in 2001 because the equivalent U.S. dollar value of the Australian dollar remained relatively stable during 2001 and increased slightly during 2002.

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. The Company does not use financial instruments to any degree to manage foreign currency, interest rate and commodity risks and does not hold or issue financial instruments to any degree for trading purposes. At December 31, 2003, the Company was exposed to some market risk with respect to foreign currency, long-term debt, and natural gas prices; however, management did not believe such risk to be material.

Foreign Currency Risk

The Company's subsidiary, Tipperary Oil and Gas (Australia) Pty Ltd ("TOGA") uses the Australian dollar as its functional currency. To the extent that business transactions in Australia are not denominated in the Australian dollar, the Company is exposed to foreign currency exchange risk. During 2003, the

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Company benefited from the non-permanent intercompany debt TOGA owed Tipperary Corporation that was denominated in U.S. dollars. The Company recorded a foreign currency gain of $2.6 million related to this intercompany debt. As this non-permanent intercompany debt is now retired, the Company does not anticipate recording significant future foreign currency gains or losses due to changes in exchange rates. 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, the Company has experienced significant growth in the 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. The Company may experience significant changes in these accounts and the standardized measure during 2004 and in future years if exchange rates are volatile; however, such volatility will not result in a loss or gain on the income statement. The majority of the Company's revenues, operating expenses and general and administrative expenses in Australia are incurred in Australian dollars. During 2003, the Company's revenues and expenses increased as a result of the strength of the Australian dollar. The Company expects its financial results will be impacted by exchange rate volatility, but does not expect a significant effect on future earnings as a result of this volatility.

Interest Rate Risk

The Company currently has a significant amount of outstanding debt and is exposed to risk resulting from changes in interest rates. While the majority of the Company's current debt has been under long-term fixed interest rate agreements, the expected new Australian debt facility will be at a floating rate. The Company is 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 rate change will result in a cost or benefit to the Company of $741,000 per year.

Commodity Price Risk

Virtually all of the Company's 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 the Company's commodity price risk. Although not anticipated, the Company may be required to recognize a non-cash ceiling test impairment, as described in Critical Accounting Polices found in Item 7 of this Form 10-K, of the Australian properties if more costs are added to the full cost pool than are supported by gas reserves or the Australian dollar weakens significantly.

The Company has in the past and plans in the future to sell significant quantities of gas or oil in the United States market. If the Company does sell significant quantities of gas or oil in the United States, it may be exposed to price volatility that could affect the carrying value of its U.S. oil and gas properties.

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ITEM 8. FINANCIAL STATEMENTS

The Company's financial statements and related audit report appear on pages 31 through 63 in this annual report:

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REPORT OF INDEPENDENT AUDITORS

To the Board of Directors and Stockholders of Tipperary Corporation:

In our opinion, the accompanying consolidated balance sheets and 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, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 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 auditing standards generally accepted in the United States of America, which 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.

/s/ PricewaterhouseCoopers LLP

Denver, Colorado
March 29, 2004

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TIPPERARY CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
($ in thousands except per share data)