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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,

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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 is