**UNITED STATES****SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

 

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**FORM 10-Q/A**

**Amendment No. 1**

 
| **ý**                         | **QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE  SECURITIES EXCHANGE ACT OF 1934**                                                                                                                                                                                                                                                                                                                                                   |
|------------------------------------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| ** **                         | ** **                                                                                                                                                                                                                                                                                                                                                                                                                               |
|                               | **For the quarterly period ended September 30, 2003**                                                                                                                                                                                                                                                                                                                                                                                    |
|                               |                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| **OR**                             |
|                               |                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| **o**                              | **TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE  SECURITIES EXCHANGE ACT OF 1934**                                                                                                                                                                                                                                                                                                                                                  |
|                               |                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| ** **                         | **For the transition period from                                  to                                  ** |
| ** **                         | ** **                                                                                                                                                                                                                                                                                                                                                                                                                               |
| **Commission  File Number 1-7796** |

 

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| **TIPPERARY CORPORATION**                                       |
|-----------------------------------------------------------------|
| (Exact name of registrant as specified in its  charter)         |
|                                                            |
| **Texas**                                                       | ** ** | **75-1236955** |
| (State or other jurisdiction of  incorporation or organization) |   | (I.R.S. Employer  Identification No.) |
|                                                            |
| **633 Seventeenth Street, Suite 1550  Denver, Colorado**        |   | **80202** |
| (Address of principal executive offices)                        |   | (Zip Code) |
|                                                            |   |   |
| **(303)  293-9379**                                             |
| (Issuer’s  telephone number)                               |

 

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

 

Yes  ý  No  o

 

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

 

Yes  o  No  ý

 

State the number of sharesoutstanding of each of the issuer’s classes of common stock, as of the latestpracticable date.

 
| **Class**                        | ** ** | **Outstanding at November 14, 2003** |
|----------------------------------|------------|--------------------------------------|
| **Common Stock, $.02 par value** | ** ** | **39,221,489 shares**                |

 

 

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**TIPPERARY CORPORATION AND SUBSIDIARIES**

** **

Indexto Form 10-Q/A

 
| EXPLANATORY NOTE                           |                                                                                            |
|--------------------------------------------|-------------------------------------------------------------------------------------------------|
|                                       |                                                                                            |
| PART I. FINANCIAL  INFORMATION (UNAUDITED) |                                                                                            |
|                                       |                                                                                            |
| Item 1.                                    | Financial Statements                                                                            |   |
|                                       |                                                                                            |   |
|                                       | Consolidated Balance  Sheets September 30, 2003 and December 31, 2002                           |   |
|                                       |                                                                                            |   |
|                                       | Consolidated  Statements of Operations Three and nine months ended September 30, 2003 and  2002 |   |
|                                       |                                                                                            |   |
|                                       | Consolidated  Statements of Cash Flows Nine months ended September 30, 2003 and 2002            |   |
|                                       |                                                                                            |   |
|                                       | Notes to  Consolidated Financial Statements                                                     |   |
|                                       |                                                                                            |   |
| Item 2.                                    | Management’s  Discussion and Analysis of Financial Condition and Results of Operations     |   |
|                                       |                                                                                            |   |
| Item 4.                                    | Controls and Procedures                                                                         |   |
|                                       |                                                                                            |   |
| PART II. OTHER INFORMATION                 |                                                                                            |
|                                       |                                                                                            |
| Item 1.                                    | Legal Proceedings                                                                               |   |
|                                       |                                                                                            |   |
| Item 6.                                    | Exhibits and  Reports on Form 8-K                                                               |   |
|                                       |                                                                                            |   |
| SIGNATURES                                 |                                                                                            |
|                                       |                                                                                            |
| EXHIBIT  INDEX                             |                                                                                            |

 

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**EXPLANATORYNOTE**

** **

This AmendmentNo. 1 on Form 10-Q is being filed to amend part I Item 4. of the Company'sQuarterly Report on Form 10-Q for the quarterly period ended September 30,2003, filed on November 14, 2003 (the "Original 10-Q"). ThisAmendment No. 1 does not otherwise alter the disclosures set forth in the Original10-Q and does not reflect events occurring after the filing of the Original10-Q. This Amendment No. 1 is effective for all purposes as of the date of thefiling of the Original 10-Q.

 

 

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**PARTI—FINANCIAL INFORMATION**

** **

**Item 1. Financial Statements**

** **

**TIPPERARY CORPORATION AND SUBSIDIARIES**

Consolidated Balance Sheets

(inthousands, except share data)

(unaudited)

 
| ** **                                                                                                              | ** ** | **September 30  2003** | ** ** | **December 31  2002** | ** ** |
|-------------------------------------------------------------------------------------------------------------------------|------------|------------------------|------------|-----------------------|------------|
| ASSETS                                                                                                                  |       |                   |       |                  |       |
| Current assets:                                                                                                         |       |                   |       |                  |       |
| Cash and cash equivalents                                                                                               |       | $                      | 1,066      |                  | 1,725      |   |
| Restricted cash                                                                                                         |       | —                 |       | 546                   |       |
| Receivables                                                                                                             |       | 2,276                  |       | 1,863                 |       |
| Other current assets                                                                                                    |       | 744                    |       | 290                   |       |
|                                                                                                                    |       |                   |       |                  |       |
| Total current assets                                                                                                    |       | 4,086                  |       | 4,424                 |       |
|                                                                                                                    |       |                   |       |                  |       |
| Property, plant and equipment, at cost:                                                                                 |       |                   |       |                  |       |
| Oil and gas properties, full cost method                                                                                |       | 105,907                |       | 75,395                |       |
| Other property and equipment                                                                                            |       | 4,467                  |       | 3,827                 |       |
|                                                                                                                    |       |                   |       |                  |       |
|                                                                                                                    |       | 110,374                |       | 79,222                |       |
| Less accumulated depreciation, depletion  and amortization                                                              |       | (7,208                 | )          | (4,882                | )          |
|                                                                                                                    |       |                   |       |                  |       |
| Property, plant and equipment, net                                                                                      |       | 103,166                |       | 74,340                |       |
|                                                                                                                    |       |                   |       |                  |       |
| Deferred loan costs                                                                                                     |       | 385                    |       | 5,751                 |       |
| Other noncurrent assets                                                                                                 |       | 467                    |       | 238                   |       |
|                                                                                                                    |       |                   |       |                  |       |
|                                                                                                                    |       | $                      | 108,104    |                  | $          | 84,753 |   |
|                                                                                                                    |       |                   |       |                  |       |
| LIABILITIES AND STOCKHOLDERS’ EQUITY                                                                               |       |                   |       |                  |       |
| Current liabilities:                                                                                                    |       |                   |       |                  |       |
| Current portion of long-term debt                                                                                       |       | 5,470                  |       | —                |       |
| Accounts payable                                                                                                        |       | 3,412                  |       | 1,384                 |       |
| Accrued liabilities                                                                                                     |       | 2,247                  |       | 1,970                 |       |
| Royalties payable                                                                                                       |       | 89                     |       | 130                   |       |
|                                                                                                                    |       |                   |       |                  |       |
| Total current liabilities                                                                                               |       | 11,218                 |       | 3,484                 |       |
|                                                                                                                    |       |                   |       |                  |       |
| Long-term debt                                                                                                          |       | 52,747                 |       | 27,899                |       |
| Long-term asset retirement obligation                                                                                   |       | 284                    |       | —                |       |
| Minority interest                                                                                                       |       | 553                    |       | 603                   |       |
|                                                                                                                    |       |                   |       |                  |       |
| Commitments and contingencies (Note 5)                                                                                  |       |                   |       |                  |       |
|                                                                                                                    |       |                   |       |                  |       |
| Stockholders’ equity                                                                                               |       |                   |       |                  |       |
| Preferred stock:                                                                                                        |       |                   |       |                  |       |
| Cumulative; par value $1.00; 10,000,000  shares authorized; none issued                                                 |       | —                 |       | —                |       |
| Non-cumulative, par value $1.00; 10,000,000  shares authorized; none issued                                             |       | —                 |       | —                |       |
| Common stock; par value $.02; 50,000,000  shares authorized; 39,231,087 shares issued and 39,221,489 shares outstanding |       | 785                    |       | 785                   |       |
| Capital in excess of par value                                                                                          |       | 149,970                |       | 149,953               |       |
| Accumulated deficit                                                                                                     |       | (111,091               | )          | (97,946               | )          |
| Accumulated other comprehensive income                                                                                  |       | 3,663                  |       | —                |       |
| Treasury stock, at cost; 9,598 shares                                                                                   |       | (25                    | )          | (25                   | )          |
|                                                                                                                    |       |                   |       |                  |       |
| Total stockholders’ equity                                                                                         |       | 43,302                 |       | 52,767                |       |
|                                                                                                                    |       |                   |       |                  |       |
|                                                                                                                    |       | $                      | 108,104    |                  | $          | 84,753 |   |

 

Seeaccompanying notes to consolidated financial statements.

 

1

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**TIPPERARY CORPORATION AND SUBSIDIARIES**

Consolidated Statements ofOperations

(inthousands, except per share data)

(unaudited)

 
| ** **                                                                | ** ** | **Three months ended  September 30** | ** ** | **Nine months ended  September 30** | ** ** |
|---------------------------------------------------------------------------|------------|--------------------------------------|------------|-------------------------------------|------------|
| ** **                                                                | ** ** | **2003**                             | ** ** | **2002**                            | ** ** | **2003** | ** ** | **2002** | ** ** |
| Revenues                                                                  |       | $                                    | 1,714      |                                | $          | 1,092 |   | $ | 4,764 |   | $ | 3,696 |   |
|                                                                      |       |                                 |       |                                |       |   |   |   |   |
| Costs and expenses:                                                       |       |                                 |       |                                |       |   |   |   |   |
| Operating                                                                 |       | 1,257                                |       | 800                                 |       | 3,325 |   | 2,108 |   |
| Depreciation, depletion and amortization                                  |       | 455                                  |       | 289                                 |       | 1,161 |   | 1,124 |   |
| Gain on sale of assets                                                    |       | —                               |       | —                              |       | — |   | (766 | ) |
| Write-down of oil and gas properties                                      |       | 165                                  |       | —                              |       | 2,386 |   | — |   |
| Asset retirement obligation accretion                                     |       | 6                                    |       | —                              |       | 18 |   | — |   |
| Recovery of prepaid drilling costs                                        |       | —                               |       | (282                                | )          | — |   | (282 | ) |
| General and administrative                                                |       | 1,353                                |       | 1,106                               |       | 4,165 |   | 3,692 |   |
|                                                                      |       |                                 |       |                                |       |   |   |   |   |
| Total costs and expenses                                                  |       | 3,236                                |       | 1,913                               |       | 11,055 |   | 5,876 |   |
|                                                                      |       |                                 |       |                                |       |   |   |   |   |
| Operating loss                                                            |       | (1,522                               | )          | (821                                | )          | (6,291 | ) | (2,180 | ) |
|                                                                      |       |                                 |       |                                |       |   |   |   |   |
| Other income (expense):                                                   |       |                                 |       |                                |       |   |   |   |   |
| Interest income                                                           |       | 13                                   |       | 16                                  |       | 35 |   | 64 |   |
| Write-off of deferred loan costs                                          |       | (5,069                               | )          | —                              |       | (5,069 | ) | — |   |
| Interest expense                                                          |       | (1,403                               | )          | (797                                | )          | (3,883 | ) | (2,191 | ) |
| Other income                                                              |       | —                               |       | —                              |       | — |   | 70 |   |
| Foreign currency exchange gain (loss)                                     |       | (1,053                               | )          | (35                                 | )          | 2,060 |   | 19 |   |
|                                                                      |       |                                 |       |                                |       |   |   |   |   |
| Total other income (expense)                                              |       | (7,512                               | )          | (816                                | )          | (6,857 | ) | (2,038 | ) |
|                                                                      |       |                                 |       |                                |       |   |   |   |   |
| Loss before income taxes                                                  |       | (9,034                               | )          | (1,637                              | )          | (13,148 | ) | (4,218 | ) |
|                                                                      |       |                                 |       |                                |       |   |   |   |   |
| Income tax benefit                                                        |       | —                               |       | —                              |       | — |   | — |   |
|                                                                      |       |                                 |       |                                |       |   |   |   |   |
| Loss before minority interest and  cumulative effect of accounting change |       | (9,034                               | )          | (1,637                              | )          | (13,148 | ) | (4,218 | ) |
|                                                                      |       |                                 |       |                                |       |   |   |   |   |
| Minority interest in loss of subsidiary                                   |       | 230                                  |       | 11                                  |       | 49 |   | 72 |   |
|                                                                      |       |                                 |       |                                |       |   |   |   |   |
| Loss before cumulative effect of accounting  change                       |       | (8,804                               | )          | (1,626                              | )          | (13,099 | ) | (4,146 | ) |
|                                                                      |       |                                 |       |                                |       |   |   |   |   |
| Cumulative effect of accounting change                                    |       | —                               |       | —                              |       | (46 | ) | — |   |
|                                                                      |       |                                 |       |                                |       |   |   |   |   |
| Net loss                                                                  |       | $                                    | (8,804     | )                                   | $          | (1,626 | ) | $ | (13,145 | ) | $ | (4,146 | ) |
|                                                                      |       |                                 |       |                                |       |   |   |   |   |
| Net loss per share                                                        |       |                                 |       |                                |       |   |   |   |   |
| Basic and diluted                                                         |       | $                                    | (.22       | )                                   | $          | (.04 | ) | $ | (.34 | ) | $ | (.11 | ) |
|                                                                      |       |                                 |       |                                |       |   |   |   |   |
| Weighted average shares outstanding                                       |       |                                 |       |                                |       |   |   |   |   |
| Basic and diluted                                                         |       | 39,221                               |       | 39,221                              |       | 39,221 |   | 39,090 |   |

 

Seeaccompanying notes to consolidated financial statements.

 

2

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**TIPPERARY CORPORATION AND SUBSIDIARIES**

Consolidated Statements ofCash Flows

(inthousands)

(unaudited)

 
| ** **                                                                   | ** ** | **Nine months ended  September 30** | ** ** |
|------------------------------------------------------------------------------|------------|-------------------------------------|------------|
| ** **                                                                   | ** ** | **2003**                            | ** ** | **2002** | ** ** |
| Cash flows from operating activities:                                        |       |                                |       |   |   |
| Net loss                                                                     |       | $                                   | (13,145    | ) | $ | (4,146 | ) |
| Adjustments to reconcile net loss to net  cash used in operating activities: |       |                                |       |   |   |
| Depreciation, depletion and amortization                                     |       | 1,161                               |       | 1,124 |   |
| Amortization and write-off of deferred loan  costs                           |       | 5,770                               |       | 1,118 |   |
| Warrants granted for services                                                |       | 6                                   |       | 7 |   |
| Minority interest in loss of subsidiary                                      |       | (49                                 | )          | (72 | ) |
| Foreign currency exchange gain                                               |       | (2,070                              | )          | — |   |
| Gain on sale of assets                                                       |       | —                              |       | (766 | ) |
| Asset retirement obligation accretion                                        |       | 18                                  |       | — |   |
| Cumulative effect of accounting change                                       |       | 46                                  |       | — |   |
| Write-down of oil and gas properties                                         |       | 2,386                               |       | — |   |
| Changes in current assets and current  liabilities:                          |       |                                |       |   |   |
| (Increase) decrease in receivables                                           |       | (178                                | )          | 54 |   |
| (Increase) decrease in other current assets                                  |       | (395                                | )          | 55 |   |
| Increase (decrease) in accounts payable and  accrued liabilities             |       | 823                                 |       | (70 | ) |
| Decrease in royalties payable                                                |       | (41                                 | )          | (93 | ) |
|                                                                         |       |                                |       |   |   |
| Net cash used in operating activities                                        |       | (5,668                              | )          | (2,789 | ) |
|                                                                         |       |                                |       |   |   |
| Cash flows from investing activities:                                        |       |                                |       |   |   |
| Proceeds from asset sales                                                    |       | 2,912                               |       | 5,623 |   |
| Capital expenditures                                                         |       | (26,340                             | )          | (19,973 | ) |
|                                                                         |       |                                |       |   |   |
| Net cash used in investing activities                                        |       | (23,428                             | )          | (14,350 | ) |
|                                                                         |       |                                |       |   |   |
| Cash flows from financing activities:                                        |       |                                |       |   |   |
| Proceeds from borrowings                                                     |       | 55,512                              |       | 11,000 |   |
| Principal repayments                                                         |       | (27,129                             | )          | (315 | ) |
| Decrease in restricted cash                                                  |       | 546                                 |       | 1,086 |   |
| Payments for deferred loan costs                                             |       | (362                                | )          | (567 | ) |
|                                                                         |       |                                |       |   |   |
| Net cash provided by financing activities                                    |       | 28,567                              |       | 11,204 |   |
|                                                                         |       |                                |       |   |   |
| Effect of exchange rate changes on cash                                      |       | (130                                | )          | — |   |
|                                                                         |       |                                |       |   |   |
| Net increase (decrease) in cash and cash  equivalents                        |       | (659                                | )          | (5,935 | ) |
|                                                                         |       |                                |       |   |   |
| Cash and cash equivalents at beginning of period                             |       | 1,725                               |       | 9,415 |   |
|                                                                         |       |                                |       |   |   |
| Cash and cash equivalents at end of period                                   |       | $                                   | 1,066      |   | $ | 3,480 |   |
|                                                                         |       |                                |       |   |   |
| Supplemental disclosure of cash flow  information:                           |       |                                |       |   |   |
| Cash paid during the period for:                                             |       |                                |       |   |   |
| Interest                                                                     |       | $                                   | 2,860      |   | $ | 1,502 |   |
| Income taxes                                                                 |       | $                                   | —     |   | $ | — |   |
| Non-cash investing and financing  activities:                                |       |                                |       |   |   |
| Issuance of stock to acquire assets                                          |       | $                                   | —     |   | $ | 450 |   |

 

Seeaccompanying notes to consolidated financial statements.

 

3

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**TIPPERARY CORPORATION AND SUBSIDIARIES**

**NOTES TOCONSOLIDATED FINANCIAL STATEMENTS**

**(Unaudited)**

** **

**NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES**

** **

Basis of Presentation

 

In the opinion ofmanagement, the accompanying unaudited consolidated financial statementsreflect all adjustments, consisting only of normal recurring adjustments, whichare necessary for a fair presentation of the financial position of TipperaryCorporation and its subsidiaries (the “Company”) at September 30, 2003, and theresults of its operations for the three-month and nine-month periods endedSeptember 30, 2003 and 2002 and its cash flows for the nine-month periods endedSeptember 30, 2003 and 2002. The consolidated financial statements include theaccounts of Tipperary Corporation and its wholly-owned subsidiaries, TipperaryOil and Gas Corporation and Burro Pipeline Corporation, and its 90%-ownedsubsidiary, Tipperary Oil and Gas (Australia) Pty Ltd (“TOGA”). Allintercompany balances have been eliminated. The accounting policies followed bythe Company are included in Note 1 to the Consolidated Financial Statements inits Annual Report on Form 10-KSB for the year ended December 31, 2002. Thesefinancial statements should be read in conjunction with the 2002 Form 10-KSBand with the Form 10-Q dated March 31, 2003 and June 30, 2003.

 

Impact of New AccountingPronouncements

 

In May 2003, the FASB issuedSFAS No. 150, “Accounting for Certain Financial Instruments withCharacteristics of Both Liabilitiesand Equity” (“SFAS 150”). SFAS 150 establishes standards on the classificationand measurement of certain financial instruments with characteristics of both liabilities and equity. The provisions ofSFAS 150 are effective for financial instruments entered into or modified after May 31, 2003, and generally toall other instruments that exist as of the beginning of the first interimfinancial reporting periodbeginning after June 15, 2003. The adoption of SFAS 150 does not have amaterial effect on the Company’s consolidatedfinancial statements.

 

In June 2001, the FASB issuedSFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), whichprovides accounting requirements for retirement obligations associated withtangible long-lived assets, including the timing of liability recognition,initial measurement of the liability, allocation of asset retirement costs toexpense, subsequent measurement of the liability, and financial statementdisclosures. SFAS 143 requires that asset retirement costs be capitalized alongwith the cost of the related long-lived asset. The asset retirement costsshould then be allocated to expense using a systematic and rational method. TheCompany has determined that it has asset retirement costs associated with wellsdrilled in Australia and the United States. The Company also expects to incurretirement costs to dismantle two gas compression plant facilities located inAustralia. The Company adopted SFAS 143 on January 1, 2003, which resulted inan increase in property, plant and equipment of $134,000 and establishment ofan asset retirement obligation of $180,000. The transition adjustment of$46,000 was reported as a cumulative effect of accounting change. If theCompany had applied the provisions of SFAS 143 as of January 1, 2002, theCompany’s asset retirement obligationwould have been $145,000 at January 1, 2002. The Company’s pro formanet loss would have been $1.631 million and $4.160 million for the three and nine months endedSeptember 30, 2002 assuming SFAS 143 had been adopted on January 1, 2002. As aresult of adopting SFAS 143, the estimated asset retirement obligationaccretion for 2003 is expected to be approximately $27,400.

 
| Beginning asset retirement obligation at  January 1, 2003 |   | $      | 180,000 |   |
|-----------------------------------------------------------|--------|--------|---------|--------|
| Asset retirement obligation accretion                     |   | 18,000 |    |
| Asset retirement obligation additions                     |   | 86,000 |    |
|                                                      |   |   |    |
| Ending asset retirement obligation at  September 30, 2003 |   | $      | 284,000 |   |

 

In June 2001, the FASBissued SFAS No. 141, “Business Combinations” (“SFAS 141”) and SFAS No. 142, “Goodwilland Intangible Assets” (“SFAS 142”). SFAS 141 and 142 became effective on July1, 2001 and January 1, 2002, respectively. SFAS 141 requires all businesscombinations initiated after June 30, 2001 to be accounted for using thepurchase method. Additionally, SFAS 141 requires companies to disaggregate andreport separately from goodwill certain

 

4

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intangible assets. SFAS 142establishes new guidelines for accounting for goodwill and other intangibleassets. Under SFAS 142, goodwill and certain other intangible assets are notamortized, but rather are reviewed annually for impairment. One interpretationbeing considered relative to these standards is that oil and gas mineral rightsheld under lease and other contractual arrangements representing the right toextract such reserves for both undeveloped and developed leaseholds should beclassified separately from oil and gas properties, as intangible assets on theCompany’s consolidated balance sheets. In addition, the disclosures required bySFAS 141 and 142 relative to intangibles would be included in the notes tofinancial statements. Historically, the Company, like many other oil and gascompanies, has included these oil and gas mineral rights held under lease andother contractual arrangements representing the right to extract such reservesas part of oil and gas properties, even after SFAS 141 and 142 becameeffective.

 

As applied to companies thathave adopted full cost accounting for oil and gas activities, the Companyunderstands that this interpretation of SFAS 141 and 142 would only affect theCompany’s balance sheets classification of proved oil and gas leaseholdsacquired after June 30, 2001 and the Company’s unproved oil and gas leaseholds.The Company’s results of operations and cash flows would not be affected, sincethese oil and gas mineral rights held under lease and other contractualarrangements representing the right to extract such reserves would continue tobe amortized in accordance with full cost accounting rules.

 

At September 30, 2003 andDecember 31, 2002, the Company had undeveloped leaseholds of approximately $3.2million and $3.0 million, respectively, that would be classified on theconsolidated balance sheet as “intangible undeveloped leaseholds” and noamounts that would be classified as “intangible developed leaseholds,” if theCompany applied the interpretations currently being discussed.

 

The Company will continue toclassify its oil and gas mineral rights held under lease and other contractualrights representing the right to extract such reserves as tangible oil and gasproperties until further guidance is provided.

 

Stock-Based Compensation

 

At September 30, 2003, theCompany had two stock-based employee option plans issued to directors andemployees and warrants granted to Company directors and employees and tonon-employees for services. The Company has chosen to continue to account forstock-based compensation using the intrinsic value method prescribed inAccounting Principles Board Opinion No. 25, “Accounting for Stock Issued toEmployees”, (“APB 25”) and has applied the disclosure provisions of SFAS 123 “Accountingfor Stock-Based Compensation” (“SFAS 123”) and SFAS 148 “Accounting forStock-Based Compensation – Transition and Disclosure – An Amendment of SFAS 123”.Accordingly, compensation cost for fixed stock options and warrants is measuredas the excess, if any, of the quoted market price of the Company’s stock at thedate of the grant over the amount a director or employee must pay to acquirethe stock. Pro forma disclosures as if the Company had adopted the costrecognition provisions of SFAS 123 are presented below.

 
| ** **                                                                                   | ** ** | **Three months ended  September 30** | ** ** | **Nine months ended  September 30** | ** ** |
|----------------------------------------------------------------------------------------------|------------|--------------------------------------|------------|-------------------------------------|------------|
| ** **                                                                                   | ** ** | **2003**                             | ** ** | **2002**                            | ** ** | **2003** | ** ** | **2002** | ** ** |
| Net loss as reported                                                                         |       | $                                    | (8,804,000 | )                                   | $          | (1,626,000 | ) | $ | (13,145,000 | ) | $ | (4,146,000 | ) |
| Add:                                                                                         |       |                                 |       |                                |       |   |   |   |   |
| Total compensation cost included in  reported net loss, net of tax                           |       | —                               |       | —                              |       | — |   | — |   |
| Deduct:                                                                                      |       |                                 |       |                                |       |   |   |   |   |
| Total compensation cost determined under  fair value based method for all awards, net of tax |       | (37,000                              | )          | (60,000                             | )          | (110,000 | ) | (181,000 | ) |
|                                                                                         |       |                                 |       |                                |       |   |   |   |   |
| Pro forma net loss                                                                           |       | $                                    | (8,841,000 | )                                   | $          | (1,686,000 | ) | $ | (13,255,000 | ) | $ | (4,327,000 | ) |
|                                                                                         |       |                                 |       |                                |       |   |   |   |   |
| Loss per share                                                                               |       |                                 |       |                                |       |   |   |   |   |
| Basic and diluted—as reported                                                           |       | $                                    | (.22       | )                                   | $          | (.04 | ) | $ | (.34 | ) | $ | (.11 | ) |
| Basic and diluted—pro forma                                                             |       | $                                    | (.23       | )                                   | $          | (.04 | ) | $ | (.34 | ) | $ | (.11 | ) |

 

5

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Ceiling Test Write-Down

 

The Company accounts for itsoil and gas properties using the full cost method. Under this method, theCompany is required to record a permanent impairment provision if the net bookvalue of its oil and gas properties less related deferred taxes exceeds aceiling value equal to the present value of the future cash inflows from provedreserves, discounted at 10% plus the cost of unproved properties not beingamortized and the lower of cost or fair value of unproved properties beingamortized, less the related tax effects. The ceiling test is computed bycountry and at the end of each quarter. The oil and gas prices used in calculatingfuture cash inflows in the United States are based on the market price on thelast day of the accounting period and in Australia are based on long termcontract prices. Oil and gas prices are generally volatile; and if the marketprices at a period end date have decreased, the Company may have to record animpairment. A loss may also be generated by the transfer of significant earlystage exploratory costs to the pool of amortizable costs, which is subject tothe ceiling test. These losses typically occur when significant costs aretransferred to the pool of amortizable costs, as a result of an unsuccessfulproject without commercially productive oil and gas production. The Companyrecorded a ceiling test write-down of $2.2 million at June 30, 2003 and$200,000 at September 30, 2003. The write-downs are the direct result ofextended production testing and further drilling that caused the Company toeliminate the proved reserves previously attributed to its Nine Mile propertiesin the United States.

 

Gas Imbalances

 

In natural gas productionoperations, joint owners sometimes sell more or less than the productionvolumes to which they are entitled based on their revenue ownership interest.The joint operating agreement includes gas balancing provisions to governproduction allocations in this situation. The Company records a natural gasimbalance in other liabilities if any excess takes of natural gas exceed itsremaining proved reserves for the property. As of September 30, 2003, theCompany had taken and sold more than its share of natural gas volumes producedfrom the Comet Ridge project, and was overproduced by approximately 1,820 MMcf.Based on the average price of $1.43 per Mcf received during the first ninemonths of 2003 from these sales, this represents $2.6 million in gas revenues.No liability has been recorded for the excess volumes taken as they do notexceed the Company’s share of remainingproved reserves. Under the terms of the gas balancing agreement, theCompany may be required to reduce the monthly volumes it sells by up to 50% of its entitled share ofsales, to enable underproduced parties to sell more than their entitled shareof the gas sales and cure theimbalance. Any reduction in monthly volumes will negatively affect the Company’srevenues, and operating expenses willnot decline proportionately.

 

Foreign Currency Translation

 

Effective April 1, 2003, theCompany changed the functional currency of its Australian subsidiary (“TOGA”)from the U.S. dollar to the Australian dollar. In April 2003, the Company beganborrowing Australian dollars under its new debt agreement with STEL (Note 2 tothe Consolidated Financial Statements). That fact, combined with TOGA’s assumptionof operations of the Comet Ridge project and increased gas sales from theproject, results in substantially all of TOGA’s transactions being denominatedin the Australian dollar. As the functional currency is the local currency, thecurrent rate method is used to translate Australian dollar financial statementsinto U.S. dollars for TOGA. All assets and liabilities are translated usingcurrent exchange rates, while revenues and expenses are translated at rates inexistence when the transactions occurred. The translation adjustment thatresults from using varying rates in the translation process is reported as acomponent of other comprehensive income and is accumulated and reported as aseparate line item in stockholders’ equity in the Company’s consolidatedfinancial statements.

 

As a result of the change infunctional currency effective April 1, 2003, the Company recorded an initialforeign currency translation adjustment of $249,000. The cumulative foreigncurrency translation adjustment as of September 30, 2003 totaled $3,663,000. Inaccordance with SFAS No. 52, “Foreign Currency Translation” (“SFAS 52”), duringthe three and nine months ended September 30, 2003, the Company recognized aforeign currency exchange gain (loss) of ($1,053,000) and $2,060,000,respectively, related to intercompany debt. Substantially all of this foreignexchange gain (loss) relates to intercompany debt TOGA owed TipperaryCorporation prior to August 15, 2003. As described in Note 2 to theConsolidated Financial Statements, the non-permanent portion of intercompanydebt was substantially reduced on August 15, 2003. This reduction is expectedto substantially reduce future foreign currency gains and losses.

 

6

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Liquidity and Operations

 

The Company anticipatesfunding operations and domestic and Australian non-discretionary exploratorycapital expenditures for the remainder of 2003 using (a) net gas revenues; (b)funds remaining (approximately $3.9 million) under the $25 million creditfacilities from Slough Trading Estates Limited (“STEL”), a UK company andwholly-owned subsidiary of Slough Estates plc and parent of Slough Estates USAInc. (“Slough”), which owns 61.3% of the Company’s outstanding common stock(See Note 2 to the Consolidated Financial Statements); (c) approximately$400,000 of net proceeds from the sale of certain oil and gas properties; and(d) approximately $4 million in additional loans from STEL or Slough.

 

In order to funddiscretionary capital expenditures in 2003 in excess of these cash resourcesand to fund capital expenditures beyond 2003, the Company will requirealternative sources of capital. Potential additional sources of funding areexpected to include additional debt financings and asset sales. The Company iscurrently in formal discussions with a group of banks interested in providingdebt financing to TOGA. The Company is seeking the financing to be (a)available in the fourth quarter of 2003, (b) secured by the Company’sconsolidated interests in the Comet Ridge project in Queensland, Australia, and(c) partially guaranteed by project Slough Estates plc, STEL’s UK parent. Ifobtained, the Company anticipates that the financing would be used to repay theCompany’s long-term debt denominated in Australian dollars with STEL and (tothe extent available) fund Comet Ridge development in 2004, 2005 and 2006.

 

Although the Companyanticipates this financing will occur, uncertainties and assumptions that aredifficult to predict with regard to timing, likelihood and degree of occurrencemay affect the Company’s ability to secure such financing.

 

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

 

**NOTE2—RELATED PARTY TRANSACTIONS**

 

At September 30, 2003, theCompany owed Slough and STEL approximately $58 million as shown in thefollowing table:

 
| **Lendor** | ** ** | **Borrower** | ** ** | **Loan  Initiated** | ** ** | **USD Current  Balance** | ** **   | **Loan  Denomination** | ** ** | **Due  Date** | ** ** | **Annual  Rate** | ** ** | **Purpose** | ** **                        |
|------------|------------|--------------|------------|---------------------|------------|--------------------------|--------------|------------------------|------------|---------------|------------|------------------|------------|-------------|-----------------------------------|
| STEL       |       | TOGA         |       | AUG 2003            |       | $                        | 29  Million  |                   | AUD        |          | FEB 2005   |             | 13         | %           | Retire debt and purchase  royalty |   |
|       |       |         |       |                |       |                     |         |                   |       |          |       |             |       |        |                              |
| STEL       |       | TOGA         |       | MAR 2003            |       | $                        | 17  million  |                   | AUD        |          | APR 2012   |             | 13         | %           | Exploration &  development    |   |
|       |       |         |       |                |       |                     |         |                   |       |          |       |             |       |        |                              |
| STEL       |       | Tipperary    |       | MAR 2003            |       | $                        | 6.5  million |                   | USD        |          | APR 2012   |             | 13         | %           | General corporate                 |   |
|       |       |         |       |                |       |                     |         |                   |       |          |       |             |       |        |                              |
| Slough     |       | Tipperary    |       | JUL 2002            |       | $                        | 4  million   |                   | USD        |          | APR 2004   |             | 4.6        | %           | General corporate                 |   |
|       |       |         |       |                |       |                     |         |                   |       |          |       |             |       |        |                              |
| Slough     |       | Tipperary    |       | JAN 2001            |       | $                        | 1.5  million |                   | USD        |          | JUL 2004   |             | 10         | %           | Purchase drilling rig             |   |

 

On August 15, 2003, TOGAborrowed $29 million from STEL for the sole purpose of paying off the $22million long-term debt owed TCW Asset Management Company (“TCW”) and to substantiallyfund the $7.7 million repurchase of the 6% overriding royalty held by TCW onthe Company’s Comet Ridge properties. As a result of retiring the TCW debt,TOGA’s intercompany debt with the Company was reduced by approximately $22million.

 

The Company recordeddeferred financing costs of approximately $6,800,000 in connection with the TCWcredit agreement, which was the then present value (discounted at 15%) of theoverriding royalty conveyed to TCW. This cost reduced the book value of theCompany’s oil and gas properties in Australia and was amortized as interestexpense over the life of the loan. Deferred loan cost also includeapproximately $1,683,000 of other costs incurred to obtain the TCW financing,which were likewise amortized as interest expense over the life of the loan.The remaining unamortized deferred loan costs of $5.1 million were expensed infull in the third quarter of 2003 with the retirement of the TCW debt.

 

In March 2003, the Companyentered into two credit facility agreements with STEL allowing the Company toborrow on an unsecured basis up to $25 million from STEL. The Company may repaythe loans in whole or in part without prepayment penalties. STEL may demandrepayment prior to the maturity date provided that STEL gives 18-month notice.

 

In January 2001, Sloughadvanced the Company $2.5 million to finance the purchase of a drilling rig tobe used in Australia. Although there are no mandatory principal payments priorto the maturity date, the Company is obligated to reduce the principal balanceby the amount of monthly rents received from the drilling contractor.

 

7

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**NOTE3—LONG-TERM DEBT—UNRELATED PARTY**

 

Through August 15, 2003, theCompany was a party to an amended and restated Credit Agreement with TCW with aprincipal balance of $22 million, which was used for development of the CometRidge project. As explained in Note 2 to the Consolidated Financial Statements,the Company has repaid this loan.

 

**NOTE 4 – LOSSPER SHARE**

 

The following table setsforth the computation of basic and diluted loss per share (“EPS”) (in thousandsexcept per share data):

 
| ** **                                                                                                                                                      | ** ** | **Three months ended  September 30** | ** ** | **Nine months ended  September 30** | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------------------------|------------|-------------------------------------|------------|
| ** **                                                                                                                                                      | ** ** | **2003**                             | ** ** | **2002**                            | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                                                                                                                                      | ** ** | ** **                           | ** ** | ** **                          | ** ** | ** ** | ** ** | ** ** | ** ** |
| Numerator:                                                                                                                                                      |       |                                 |       |                                |       |   |   |   |   |
| Net loss                                                                                                                                                        |       | $                                    | (8,804     | )                                   | $          | (1,626 | ) | $ | (13,145 | ) | $ | (4,146 | ) |
|                                                                                                                                                            |       |                                 |       |                                |       |   |   |   |   |
| Denominator:                                                                                                                                                    |       |                                 |       |                                |       |   |   |   |   |
| Weighted average shares outstanding                                                                                                                             |       | 39,221                               |       | 39,221                              |       | 39,221 |   | 39,090 |   |
| Effect of dilutive securities:                                                                                                                                  |       |                                 |       |                                |       |   |   |   |   |
| Assumed conversion of dilutive options and  warrants                                                                                                            |       | —                               |       | —                              |       | — |   | — |   |
|                                                                                                                                                            |       |                                 |       |                                |       |   |   |   |   |
| Weighted average shares and dilutive  potential common shares                                                                                                   |       | 39,221                               |       | 39,221                              |       | 39,221 |   | 39,090 |   |
|                                                                                                                                                            |       |                                 |       |                                |       |   |   |   |   |
| Basic and diluted loss per share                                                                                                                                |       | $                                    | (.22       | )                                   | $          | (.04 | ) | $ | (.34 | ) | $ | (.11 | ) |
|                                                                                                                                                            |       |                                 |       |                                |       |   |   |   |   |
| Number of shares of potentially dilutive  common stock from the exercise of options and warrants not included in EPS  because they would have been antidilutive |       | 494                                  |       | 82                                  |       | 212 |   | 60 |   |
|                                                                                                                                                            |       |                                 |       |                                |       |   |   |   |   |
| Total common stock options and warrants  that could potentially dilute basic EPS in future periods                                                              |       | 3,573                                |       | 3,488                               |       | 3,573 |   | 3,488 |   |

 

**NOTE5—COMMITMENTS AND CONTINGENCIES**

 

The Company, TOGA and twounaffiliated working interest owners are plaintiffs in a lawsuit filed in 1998,styled*Tipperary Corporation andTipperary 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 Ridgeproject. The plaintiffs allege, among other matters, that Tri-Star and/or theindividual defendants failed to operate the project in a good and workmanlikemanner and committed various other breaches of a joint operating contract,breached a previous mediation agreement, committed certain breaches offiduciary and other duties owed to the plaintiffs, and committed fraud inconnection with the project. Tri-Star answered the allegations, and filed acounterclaim alleging tortious interference with respect to the contracts, theauthority to prospect covering the project and contractual relationships withvendors; commercial disparagement; foreclosure of operator’s lien andalternativelyforfeitureof undeveloped acreage; unjust enrichment and declaratory relief. As ofFebruary 2001, the District Court enjoined Tri-Star from asserting any forfeiture claims basedupon events prior to that date. In March 2002, the court entered its Writ ofTemporary Injunction (the “Injunction”)to enforce the votes of a majority-in-interest of the parties under the jointoperating agreement to remove Tri-Staras operator and replace it with TOGA, and TOGA did succeed Tri-Star as operatoron March 22, 2002. All available appeals have been exhausted. Therefore, TOGA will continue as operator of theComet Ridge Project at least through the conclusion of a trial on the merits, and thereafter if successfulat trial.

 

In June 2002, the DistrictCourt ruled as unenforceable the arbitration provisions of the existingmediation agreement between the parties. The Eighth District Court of Appealsaffirmed the action of the District Court, and Tri-Star filed a Petition forReview in the Supreme Court of Texas. The Company has filed a response to thePetition for Review. The

 

8

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Supreme Court has discretionto either hear, or refuse to hear, the appeal, and no decision has yet beenannounced. Although pre-trial discovery is proceeding, the pending appealcontinues to delay the trial on the merits, and a new trial date will not beset before all appellate proceedings are resolved.

 

In August 2003, the DistrictCourt heard the Company’s Motion to Compel Compliance with Amended Writ ofTemporaryInjunction. OnOctober 1, 2003, the Court signed an Order finding that Tri-Star willfullydisobeyed the Injunction, ordering Tri-Star to cooperate with the Operator and, among other things, to execute apower of attorney to allow the Company to deal directly with the Department of Natural Resources and Mines inQueensland, and the surface owners, on matters pertaining to the Comet Ridge Project.In addition, the Court has indicated it will conduct a show cause hearing todetermine whether sanctions for Tri-Star’s past violations of the Injunction,and conditional sanctions to deter future violations, should be imposed.

 

Prior to taking overoperations, the Company and other plaintiffs sent payments on disputed Tri-Starbillings to the Registry of the Court. The amount now held in the Registry ofthe Court due to these payments and accrued interest is $1.3 million. TheCompany and other plaintiffs have filed a Motion to Withdraw, seeking return ofthe $1.3 million held in the Registry of the Court, and that the Motion will beheard in the near term. Upon return of the $1.3 million from the Court, theCompany expects to return approximately $200,000 to Comet Ridge partners andwill record $1.1 million as a recovery of prepaid drilling costs.

 

To the extent the Courteventually finds that all or a portion of the disputed Tri-Star billings wereinappropriate, Tri-Star would owe up to $1.2 million additional monies to theCompany. The additional sums, if the full $1.2 million is received, would berecorded as a $1 million recovery of capital costs and a $200,000 recovery ofoperating expenses. It is the Company’s opinion that the May 29, 2003 AppellateCourt affirmation of the lower court’s decision strongly supports the Company’sposition that the billings were inappropriate.

 

The Company may be entitledto additional damages based upon Tri-Star’s billing and handling of thearbitration process if the June 21, 2002 ruling of the District Court is upheldon final appeal.

 

**NOTE6—OPERATIONS BY GEOGRAPHIC AREA**

 

The Company has oneoperating and reporting segment—oil and gas exploration, development andproduction—in the United States and Australia. Information about the Company’soperations by geographic area is shown below (in thousands):

 
| ** **                                                       | ** ** | **Australia** | ** ** | **United  States** | ** ** | **Total** | ** ** |
|------------------------------------------------------------------|------------|---------------|------------|--------------------|------------|-----------|------------|
| Operating revenue for the three months  ended September 30, 2003 |       | $             | 1,710      |               | $          | 4         |       | $ | 1,714 |   |
| Operating revenue for the three months  ended September 30, 2002 |       | $             | 1,227      |               | $          | (135      | )          | $ | 1,092 |   |
|                                                             |       |          |       |               |       |      |       |
| Operating revenue for the nine months ended  September 30, 2003  |       | $             | 4,753      |               | $          | 11        |       | $ | 4,764 |   |
| Operating revenue for the nine months ended  September 30, 2002  |       | $             | 3,267      |               | $          | 429       |       | $ | 3,696 |   |
|                                                             |       |          |       |               |       |      |       |
| Property, plant and equipment, net, at  September 30, 2003       |       | $             | 96,868     |               | $          | 6,298     |       | $ | 103,166 |   |
| Property, plant and equipment, net, at  December 31, 2002        |       | $             | 66,881     |               | $          | 7,459     |       | $ | 74,340 |   |
|                                                                  |            |               |            |                    |            |           |            |  |  |  |  |

 

9

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**NOTE 7 – PROPERTY,PLANT AND EQUIPMENT**

 

A summary of property, plantand equipment follows:

 
| ** **                                                 | ** ** | **September 30  2003** | ** ** | **December 31  2002** | ** ** |
|------------------------------------------------------------|------------|-----------------------------|------------|----------------------------|------------|
| Evaluated  oil and gas properties:                         |       |                        |       |                       |       |
| Evaluated  Australian properties                           |       | $                           | 93,467     |                       | $          | 64,469 |   |
| Evaluated  domestic properties                             |       | 12                          |       | 986                        |       |
| Unevaluated  oil and gas properties:                       |       |                        |       |                       |       |
| Unevaluated  Australian properties                         |       | 6,301                       |       | 3,619                      |       |
| Unevaluated  domestic properties                           |       | 6,127                       |       | 6,321                      |       |
|                                                       |       |                        |       |                       |       |
| Oil and gas  properties                                    |       | 105,907                     |       | 75,395                     |       |
| Other  property and equipment                              |       | 4,467                       |       | 3,827                      |       |
|                                                       |       |                        |       |                       |       |
|                                                       |       | 110,374                     |       | 79,222                     |       |
| Less  accumulated depreciation, depletion and amortization |       | (7,208                      | )          | (4,882                     | )          |
|                                                       |       |                        |       |                       |       |
| Property,  plant and equipment, net                        |       | $                           | 103,166    |                       | $          | 74,340 |   |

 

On August 15, 2003 theCompany purchased TCW’s royalty interest in the Comet Ridge Project for $7.7million. This amount is included in evaluated Australian properties.

 

10

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**Item 2.Management’s Discussion and Analysis**

 

Information within thisreport contains forward-looking statements within the meaning of the PrivateSecurities Litigation Reform Act of 1995 that are based on management’sbeliefs, assumptions, current expectations, estimates and projections about theoil and gas industry, the world economy and about the Company itself. Wordssuch as “may,” “will,” “expect,” “anticipate,” “estimate” or “continue,” orcomparable words are intended to identify such forward-looking statements. Inaddition, all statements other than statements of historical facts that addressactivities that the Company expects or anticipates will or may occur in thefuture are forward-looking statements. These statements are not guarantees offuture performance and involve certain risks, uncertainties and assumptionsthat are difficult to predict with regard to timing, extent, likelihood anddegree of occurrence. Therefore, actual results and outcomes may materiallydiffer from what may be expressed or forecasted in such forward-lookingstatements. Furthermore, the Company undertakes no obligation to update, amendor clarify forward-looking statements, whether as a result of new information,future events or otherwise. Readers are encouraged to read the SEC filings ofthe Company, particularly its Form 10-KSB for the year ended December 31,2002, for meaningful cautionary language disclosing why actual results may varymaterially from those anticipated by management.

 

***Overview***

 

*Australia*

 

The Company’s activities inAustralia are conducted substantially through the Company’s 90%-ownedAustralian subsidiary, Tipperary Oil & Gas (Australia) Pty Ltd (“TOGA”). Asof September 30, 2003, the Company owned a 73% capital interest and a69.52% pre-royalty revenue interest in the Comet Ridge project in Queensland,Australia. This project comprises approximately 1,058,000 acres in the BowenBasin and includes five petroleum leases covering approximately 278,000 acres,Authority to Prospect (“ATP”) 526 covering approximately 687,000 acres, and ATP653 covering approximately 93,000 acres.

 

An ATP allows the holder toundertake a range of exploration activities, including geophysical surveys,field mapping and exploratory drilling. Each ATP requires the expenditure of anamount of exploration costs as determined by Queensland’s Department of NaturalResources and Mines (“Queensland DNRM”) and is subject to renewal every fouryears. Once a petroleum resource is identified, the holder of an ATP may applyfor a petroleum lease, which provides the lessee with the ability to conductadditional exploration, development and production activities.

 

As of November 1, 2003,the Company has met its 2003 expenditure requirements for ATP 526 and ATP 653.ATP 526 and 653 have initial terms expiring on October 31, 2004 and September 30,2006, respectively.

 

The following table summarizesfield development progress on the Comet Ridge project. The Companysubstantially completed the installation of a second compression plant facilityin October 2003. In November 2003 the Company expects to begincompressing gas utilizing the new facility, providing for the field a currentsales capacity of approximately 30 MMcf per day. The field has an approximateadditional 11 MMcf per day of sales capacity from wells not yet connected tothe compressor facilities. Upon connection of these wells, the field would havetotal sales capacity of 41 MMcf per day. Actual field sales at September 30,2003 were 14 MMcf per day. During September 2003 the project’s mainpurchaser of gas reduced nominations by approximately 3 MMcf per day. In November 2003nominations increased and total sales volumes are currently 16 MMcf per day.The Company is in discussions with its major customer and various others forshort-term and long-term contracts for the sale of additional gas from theComet Ridge field. The Company is equipping wells to allow future production tomore closely match sales demand so as to minimize flaring of gas at the wells.

 

11

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**Comet RidgeOperations Review:**

 
| ** **                           | ** ** | **September 30  2003** | ** ** | **June 30  2003** | ** ** | **March 31  2003** | ** ** | **December 31  2002** | ** ** |
|--------------------------------------|------------|-----------------------------|------------|------------------------|------------|-------------------------|------------|----------------------------|------------|
| Well Status  (Number of Gross Wells) |       |                        |       |                   |       |                    |       |                       |       |
| Selling                              |       | 36                          |       | 36                     |       | 34                      |       | 33                         |       |
| Dewatering  or Shut-in               |       | 41                          |       | 28                     |       | 26                      |       | 26                         |       |
|                                 |       |                        |       |                   |       |                    |       |                       |       |
| Producing                            |       | 77                          |       | 64                     |       | 60                      |       | 59                         |       |
| Being  Evaluated                     |       | 13                          |       | 13                     |       | 11                      |       | 10                         |       |
| To be  Plugged and Abandoned         |       | 2                           |       | 2                      |       | 3                       |       | 3                          |       |
| Plugged and  Abandoned               |       | 2                           |       | 1                      |       | 1                       |       | 1                          |       |
|                                 |       |                        |       |                   |       |                    |       |                       |       |
| Drilled                              |       | 94                          |       | 80                     |       | 75                      |       | 73                         |       |
|                                 |       |                        |       |                   |       |                    |       |                       |       |
| Gross Daily  Volumes (MMcf)          |       |                        |       |                   |       |                    |       |                       |       |
| Sold                                 |       | 14                          |       | 17                     |       | 17                      |       | 19                         |       |
| Flared                               |       | 4                           |       | 10                     |       | 7                       |       | 4                          |       |
| Used for  Compression Fuel           |       | 2                           |       | 2                      |       | 2                       |       | 2                          |       |
|                                 |       |                        |       |                   |       |                    |       |                       |       |
| Produced                             |       | 20                          |       | 29                     |       | 26                      |       | 25                         |       |

 

The Company has drilledapproximately 20 wells on the Comet Ridge project during the first nine monthsof 2003. The Company plans to drill approximately 10 more wells in theremainder of 2003. Of the wells drilled or to be drilled in 2003, approximatelynine wells are considered exploratory wells. The remaining wells drilled are indevelopment locations and are expected to contribute to gas sales volumes afterthe gathering system is expanded to include these wells and new gas salescontracts are executed. The drilling was substantially funded under a $25million borrowing facility entered into in March 2003 with Slough TradingEstates Limited, a United Kingdom company which is the parent company of the Company’smajority shareholder. See Note 2 to the Consolidated Financial Statements.

 

During the first nine monthsof 2003, the Company sold 100% of the gas for which it had sales contracts inAustralia under two contracts with ENERGEX Retail Pty Ltd (“ENERGEX”), anunaffiliated customer. The first contract has delivery requirements of up toapproximately 5,500 Mcf of gas per day through December 2003. A secondfive-year contract, entered into with ENERGEX effective June 1, 2000, hasdelivery requirements of up to approximately 15,000 Mcf of gas per day. In December 2002,the Company entered into a gas sales agreement with Origin Energy RetailLimited (“OERL”), a subsidiary of Origin Energy Limited, to supply approximately9 Bcf per year (i.e., approximately 25,000 Mcf of gas per day) net to theCompany’s interests, for thirteen years beginning May 2007. Origin EnergyLimited is a large Australian integrated energy company which, throughsubsidiaries, owns nearly 24% of the Comet Ridge project.

 

Effective June 30,2003, the Company extended the agreement with Queensland Fertilizer AssetsLimited (“QFAL”) until December 31, 2003 to supply 260 Bcf of gas over a20-year period beginning in mid 2006 to a fertilizer plant QFAL is proposing toconstruct in southeastern Queensland. Prior to December 31, 2003, QFALmust obtain commitments to finance construction of the fertilizer plant or theCompany will be released from its gas supply commitment unless the agreement isextended. The Company believes it has reasonable certainty, based upon the gasmarket in Eastern Australia, that this production can be sold in the market, ifnot sold to QFAL.

 

In addition to the interestin the Comet Ridge project, TOGA holds a 100% interest in ATP’s 655 and 675covering approximately 278,000 acres in total as of September 30, 2003.ATP’s 655 and 675 have initial terms expiring on October 31, 2003 and February 29,have2004, respectively. TOGA has drilled and completed a total of six exploratorywells on these ATPs, three of which are being tested and evaluated, and threeof which were plugged and abandoned. The Company has applied for renewal on ATP655 on the acreage held at October 31, 2003. The Company expectsadditional exploratory work will be conducted in 2004. TOGA has met all priorterm expenditure requirements on retained acreage. TOGA also holds a 25%interest in ATP 554, which covers approximately 111,000 acres.

 

During the current termending October 31, 2003, ATP 655 had remaining expenditure requirementstotaling approximately $924,000. The Company met a portion of those expenditurerequirements and has made application to the Queensland DNRM for the remainingexpenditure requirements to be extended to October 31, 2004 in associationwith the

 

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application for renewaldiscussed previously. During the current term ending February 29, 2004,ATP 675 has no remaining expenditure requirements. The Company will continue toevaluate ATP’s 655 and 675 and will either meet the expenditure requirementsor relinquish additional acreage based upon evaluation of data. On ATP 554several conditions must be met by a third party before the Company can determine its commitment.

 

***United States***

 

The Company holds a 50%working interest in the Lay Creek coalseam gas project located in MoffatCounty, Colorado. The project includes various leasehold interests coveringover 82,000 gross acres. Koch Exploration Company (“Koch”), an unaffiliatedthird party, holds the remaining 50% working interest under the terms ofan agreement to conduct exploratory drilling over this area jointly. On October 1, 2003, through jointagreement with the Company, Koch became operator of the Lay Creek project. Kochpaid the Company approximately $2 million for this interest at closing in May2001 and agreed to pay the Company approximately $2 million for the Company’sshare of costs to drill and complete wells on the project acreage. The Companydrilled and completed two exploratory coalseam gas wells on this acreage during2001 and completed a four-well pilot drilling program around one of the exploratorywells in early May 2002. During the third and fourth quarters of 2002, theCompany drilled four additional exploratory coalseam gas wells offsetting thesecond exploratory well drilled in 2001 on the project. The Company iscurrently evaluating the gas and water production from these two five-wellpilot programs in order to determine economic viability of the production. The Companyand Koch plan to begin drilling additional pilot wells in December 2003offsetting the second five-well pilot program.

 

In February 2002, theCompany sold a 60% interest in the Nine Mile Prospect, conventional oil and gasexploration prospect, which is also located in Moffat County, Colorado, to ElmRidge Resources (“Elm Ridge”), an unaffiliated third party, for approximately $595,000.The project comprises approximately 49,000 gross acres. Elm Ridge also agreedto pay one-half of the Company’s share of drilling costs to an agreed casingpoint on the first well for its 40% retained interest. In September 2002,the Company announced the completion and initial testing of the Federal 34-1 onthe prospect. Since then the Company has become the operator of the project, twodry holes were drilled and the Federal 34-1 test has not been as positive asinitially projected. As a result, the Company recorded domestic ceiling testwrite-downs at June 30, 2003 of $2.2 million and $200,000 at September 30,2003 under the full cost method of accounting. In exchange for Tipperaryassuming Elm Ridge’s obligation for plugging and abandoning costs, Elm Ridgehas assigned its interest in portions of the Nine Mile prospect to Tipperary.The Company is evaluating the Nine Mile project and is seeking industrypartners before resuming exploratory work.

 

In November 2002, theCompany sold to Kerr-McGee Rocky Mountain Corporation (“Kerr-McGee’), anunaffiliated third party, interests ranging from 75% to 80% in the Frenchmanand Republican prospects in eastern Colorado for $4,800,000 in cash. The Companyretained the remaining 25% to 20% interests in the acreage. Total acreage inthe project is approximately 280,000 gross acres. The Company and Kerr-McGeesimultaneously entered into a joint operating agreement designating Kerr-McGeeas operator. In the second quarter of 2003, the Company drilled its first wellon the Frenchman prospect and conducted a gas production test and is evaluatingthe results. During the third quarter of 2003, the Company drilled fouradditional wells of which two were completed and two were plugged andabandoned. The Company has conducted gas production tests on one of thecompleted wells and is evaluating the results.

 

In July 2003, theCompany sold to an unaffiliated third party, a 75% interest in the Statelineprospect in western Nebraska for approximately $3 million in cash. The Companyretained a 25% interest in the acreage. Total gross acreage sold in the projectis approximately 97,000 acres. In October 2003, the Company soldadditional acreage to the same party, bringing total sales proceeds to approximately$3.2 million and total gross acreage sold to 117,000. The purchaser will serveas operator of the project. In accordance with the full cost accounting rules,the Company is recording the proceeds as a reduction of its domestic full costpool, with no gain being recognized.

 

***Financial Condition, Liquidity and Capital Resources***

 

The Company had unrestrictedcash and cash equivalents of $1,066,000 as of September 30, 2003, comparedto $1,725,000 as of

December 31, 2002.During the third quarter of 2003, the Company received approximately $36million in cash, drawing down $7

million from the $25 millionlong-term, unsecured credit facilities described in Note 2 to the ConsolidatedFinancial Statements and

borrowing $29 million fromSTEL also discussed in Note 2 to the Consolidated Financial Statements. The $7million

 

13

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described previously wasprimarily used to fund ongoing development of the Comet Ridge project while the$29 million was used to retire a $22 million debt with TCW and purchase a $7.7million royalty interest TCW held in the Comet Ridge project. The Company hasfunded operations and capital expenditures excluding the purchase of the TCW royaltyinterest for the nine months ended September 30, 2003 using primarily (a)$1.7 million of cash on hand at December 31, 2002, (b) a $4.7 millionshort-term loan from Slough in February and March 2003 that wasrepaid on April 2, 2003, (c) $21.1 million in borrowings from STEL underthe $25 million facility and (d) proceeds of $2.9 million from the sale ofassets.

 

The Company anticipatesfunding operations and domestic and Australian non-discretionary exploratorycapital expenditures for the remainder of 2003 using (a) net gas revenues; (b)funds remaining (approximately $3.9 million) under the $25 million creditfacilities from Slough Trading Estates Limited (“STEL”), a UK company andwholly-owned subsidiary of Slough Estates plc and parent of Slough Estates USAInc. (“Slough”), which owns 61.3% of the Company’s outstanding common stock(See Note 2 to the Consolidated Financial Statements); (c) approximately$400,000 of net proceeds from the sale of certain oil and gas properties; and(d) approximately $4 million in additional loans from STEL or Slough.

 

In order to funddiscretionary capital expenditures in 2003 in excess of these cash resourcesand to fund capital expenditures beyond 2003, the Company will requirealternative sources of capital. Potential additional sources of funding areexpected to include additional debt financings and asset sales. The Company iscurrently in formal discussions with a group of banks interested in providingAUD $150 million in senior debt financing to TOGA. The Company is seeking thefinancing to be (a) substantially available in December of 2003, (b)secured by the Company’s consolidated interests in the Comet Ridge project inQueensland, Australia, and (c) partially guaranteed by Slough Estates plc, STEL’sUK parent. If obtained, the Company anticipates that the financing would beused to repay the Company’s long-term debt with STEL, including the $29 millionlong-term debt the Company has borrowed as described in Note 2 to theConsolidated Financial Statements, and (to the extent available) fund CometRidge development in 2004, 2005, and 2006.

 

On an ongoing basis, theCompany seeks to sell its interests in its prospective acreage in the UnitedStates and retain carried working interests. In the event of such sales, theCompany generates cash to reduce its investment in individual projects and fundexploration costs. However, in the event that sufficient capital cannot begenerated from property sales or other funding cannot be obtained, the Companywill be required to curtail planned expenditures and may have to selladditional acreage and/or relinquish acreage at prices that are not favorableto the Company.

 

Net cash used by operatingactivities was $5,668,000 during the nine months ended September 30, 2003compared to $2,789,000 of cash used during the same period last year. Theincrease in cash used for operations in 2003 resulted primarily from $1.3million in increased interest expense on debt used to fund propertyacquisition, exploration and development, increased operating expenses of $1.2million necessary to fund costs associated with increased gas sales inAustralia and $473,000 in increased general and administrative expense. Thefollowing table provides a detailed analysis of capital expenditures of $26.3 millionduring the nine months ended September 30, 2003.

 

14

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Capital ExpendituresActivity

(in thousands)

 

| Australia:                            |   |   |   |
|---------------------------------------|--------|--------|--------|
| Comet Ridge  drilling and completion  |   | $      | 9,100  |   |
| Comet Ridge  facilities and equipment |   | 5,021  |   |
| Comet Ridge  royalty purchase         |   | 7,669  |   |
| Other                                 |   | 401    |   |
|                                  |   |   |   |
| Domestic:                             |   |   |   |
| Leasehold  acquisitions               |   | 1,688  |   |
| Nine Mile  drilling and completion    |   | 1,180  |   |
| Lay Creek  drilling and completion    |   | 508    |   |
| Frenchman  exploratory                |   | 138    |   |
| Other                                 |   | 635    |   |
|                                  |   |   |   |
| Total                                 |   | $      | 26,340 |   |

 

In January 2001, Sloughadvanced the Company $2.5 million for the purchase of a drilling rig which theCompany has leased to an unaffiliated drilling contractor in Australia. Thisloan bears interest at a fixed rate of 10% per annum and matures on July 31,2004. Principal payments are due monthly equal to all rents the Companyreceives from the drilling contractor and for accrued interest on the balanceof the loan. However, there are no mandatory principal payments prior to thematurity. During the first nine months of 2003, the Company received $440,000in rent which was used for principal payments. As of September 30, 2003,the balance due on this loan was $1.47 million. The drilling contractor has anoption to buy the drilling rig from the Company prior to June 2006 for acash payment equal to $1.47 million as of September 30, 2003 less anysubsequent payments made by the contractor after September 30, 2003through the date the option is exercised.

 

15

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***Results of Operations—Comparison of the Three Months Ended September 30,2003 and 2002***

 

The Company incurred a netloss of $8,804,000 for the three months ended September 30, 2003, comparedto a net loss of $1,626,000 for the three months ended September 30, 2002.The increased net loss for the three months ended September 30, 2003 isprimarily due to the $5.1 million write-off of deferred financing costsdescribed in Note 2 to the Consolidated Financial Statements. Additionally, theCompany experienced in the third quarter a foreign exchange loss of $1.1million on accounts related to its Australian operations which contributedfurther to the increased net loss in 2003. The table below provides acomparison of operations for the three months ended September 30, 2003with those of the prior year’s quarter. The table is intended to provide a comparativereview of significant operational items and, accordingly, nominal differencesmay exist from the amounts presented in the accompanying financial statements.Certain prior period amounts have been reclassified to ensure comparability.

 
| ** **                                                          | ** ** | **Three Months Ended  September 30** | ** ** | **Increase** | ** ** | **%Increase**  | ** ** |
|---------------------------------------------------------------------|------------|-------------------------------------------|------------|--------------|------------|----------------|------------|
| ** **                                                          | ** ** | **2003**                                  | ** ** | **2002**     | ** ** | **(Decrease)** | ** ** | **(% Decrease)** | ** ** |
| **Worldwide  operations:**                                          |       |                                      |       |         |       |           |       |   |   |
| Operating  revenue                                                  |       | $                                         | 1,714,000  |         | $          | 1,092,000      |       | $ | 622,000 |   | 57 | % |
| Gas volumes  (Mcf)                                                  |       | 1,149,000                                 |       | 984,000      |       | 165,000        |       | 17 | % |
| Oil volumes  (Bbls)                                                 |       | —                                    |       | (2,900       | )          | 2,900          |       | N/A |   |
| Average gas  price per Mcf                                          |       | $                                         | 1.49       |         | $          | 1.19           |       | $ | 0.30 |   | 25 | % |
| Average oil  price per Bbl                                          |       | $                                         | —     |         | $          | 26.21          |       | (26.21 | ) | N/A |   |
| Operating  expenses                                                 |       | $                                         | 1,256,000  |         | $          | 807,000        |       | $ | 449,000 |   | 56 | % |
| Average  operating cost per Mcfe equivalent (“Mcfe”) sold |       | $                                         | 1.09       |         | $          | 0.83           |       | $ | 0.26 |   | 32 | % |
| General and  administrative                                         |       | $                                         | 1,353,000  |         | $          | 1,106,000      |       | $ | 247,000 |   | 22 | % |
| Depreciation,  depletion and amortization (“DD&A”)    |       | $                                         | 455,000    |         | $          | 289,000        |       | $ | 166,000 |   | 57 | % |
| Write-off of  deferred loan costs                                   |       | $                                         | 5,069,000  |         | $          | —         |       | $ | 5,069,000 |   | N/A |   |
| Interest  expense                                                   |       | $                                         | 1,403,000  |         | $          | 797,000        |       | $ | 606,000 |   | 76 | % |
|                                                                |       |                                      |       |         |       |           |       |   |   |
| **Australia  operations:**                                          |       |                                      |       |         |       |           |       |   |   |
| Operating  revenue                                                  |       | $                                         | 1,710,000  |         | $          | 1,227,000      |       | $ | 483,000 |   | 39 | % |
| Gas volumes  (Mcf)                                                  |       | 1,149,000                                 |       | 1,002,000    |       | 147,000        |       | 15 | % |
| Average gas  price per Mcf                                          |       | $                                         | 1.49       |         | $          | 1.22           |       | $ | 0.27 |   | 22 | % |
| Operating  expenses                                                 |       | $                                         | 978,000    |         | $          | 723,000        |       | $ | 255,000 |   | 35 | % |
| Average  operating cost per Mcf sold                                |       | $                                         | 0.85       |         | $          | 0.72           |       | $ | 0.13 |   | 18 | % |
| Oil and Gas  property DD&A                                      |       | $                                         | 417,000    |         | $          | 270,000        |       | $ | 147,000 |   | 54 | % |
| Other  DD&A                                                     |       | $                                         | 25,000     |         | $          | 8,000          |       | $ | 17,000 |   | 213 | % |
| Oil and Gas  DD&A rate per Mcf sold                             |       | $                                         | 0.36       |         | $          | 0.27           |       | $ | 0.09 |   | 33 | % |
|                                                                |       |                                      |       |         |       |           |       |   |   |
| **Domestic  operations:**                                           |       |                                      |       |         |       |           |       |   |   |
| Operating  revenue                                                  |       | $                                         | 4,000      |         | $          | (135,000       | )          | $ | 139,000 |   | N/A |   |
| Gas volumes  (Mcf)                                                  |       | 1,000                                     |       | (18,000      | )          | 19,000         |       | N/A |   |
| Oil volumes  (Bbls)                                                 |       | —                                    |       | (2,900       | )          | 2,900          |       | N/A |   |
| Average gas  price per Mcf                                          |       | $                                         | 4.08       |         | $          | 3.28           |       | $ | 0.80 |   | 24 | % |
| Average oil  price per Bbl                                          |       | $                                         | —     |         | $          | 26.21          |       | (26.21 | ) | N/A |   |
| Operating  expenses                                                 |       | $                                         | 278,000    |         | $          | 84,000         |       | $ | 194,000 |   | 231 | % |
| Average  operating cost per Mcfe sold                               |       | $                                         | 278.00     |         | $          | —         |       | 278.00 |   | N/A |   |
| Oil and Gas  property DD&A                                      |       | $                                         | —     |         | $          | —         |       | $ | — |   | 0 | % |
| Other  DD&A                                                     |       | $                                         | 13,000     |         | $          | 12,000         |       | $ | 1,000 |   | 8 | % |
| Oil and Gas  DD&A rate per Mcfe sold                            |       | —                                    |       | $            | —     |           | —     |   | 0 | % |

 

The following narrative should be read inconjunction with the above table

 

16

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Revenues and Sales Volumes

 

Gas volumes sold inAustralia increased 15% due to increased gas sales from existing wells and anincrease in gas deliveries. Gas revenues in Australia increased by 39% due tothe increase in sales volumes, an increase in the average sales price receivedand changes in exchange rates. The Company’s gas sales contracts in Australia arelong-term fixed price contracts with yearly adjustments for inflation. The 22%increase in average gas sales price in Australia is due primarily to anapproximate 14% increase in the value of the Australian dollar in relation tothe U.S. dollar and inflation adjustments.

 

In natural gas productionoperations, joint owners sometimes sell more or less than the productionvolumes to which they are entitled based on their revenue ownership interest.The joint operating agreement includes gas balancing provisions to governproduction allocations in this situation. The Company records a natural gasimbalance in other liabilities if any excess takes of natural gas exceed itsremaining proved reserves for the property. As of September 30, 2003, theCompany had taken and sold more than its share of natural gas volumes producedfrom the Comet Ridge project, and was overproduced by approximately 1,820 MMcf.Based on the average price of $1.43 per Mcf received during the first ninemonths of 2003 from these sales, this represents $2.6 million in gas revenues.No liability has been recorded for the excess volumes taken as they do notexceed Company’s share of remaining proved reserves. Under the terms of the gasbalancing agreement, the Company may be required to reduce the monthly volumesit sells by up to 50% of its entitled share of sales, to enable underproducedparties to sell more than their entitled share of the gas sales and cure theimbalance. Any reduction in monthly volumes will negatively affect theCompany’srevenues, and operating expenses will not decline proportionately.

 

During the third quarter of2003, the Company had minimal domestic revenue. Domestic revenues and volumesin 2002 related to the West Buna field which the Company sold in the thirdquarter of 2002.

 

Costs and Expenses

 

Operating expenses inAustralia increased 35% due to an increase in the number of producing wells,increased costs associated with delivering increasing gas volumes and anapproximate 14% decrease in the value of the U.S. dollar in relation to theAustralian dollar. Average operating cost per Mcf sold increased 18% to $0.85for the three months ended September 30, 2003. If the field were sellinggas at the field’s current production and compression capacity, management estimatesoperating costs per Mcf would approximate $0.40. Australian oil and gasproperty DD&A expense increased 54% due to higher production volumes andhigher finding costs for reserve additions in the third quarter.

 

Domestic operating expensesin the third quarter of 2003 are largely attributable to the Lay Creek coal bedmethane project where the initial ten wells are in the early dewatering phase.Without these Lay Creek operating expenses, the average domestic operating costper Mcf sold would be reduced substantially to $2.00 per Mcf. There were nodomestic DD&A expenses in 2003 and 2002 due to the aforementioned sale ofthe Company’s West Buna field.

 

General and administrative (“G&A”)expenses for the third quarter of 2003 increased 22% when compared to the threemonths ended September 30, 2002. For the third quarter of 2003, increasedG&A costs can be attributed to assuming operations at Comet Ridge and theongoing litigation with Tri-Star. See Note 5 to the Consolidated FinancialStatements.

 

Other Income (Expense)

 

In the third quarter of 2003the Company wrote off $5,069,000 in deferred loan costs related to the TCW loanwhich was retired on August 15, 2003. Interest expense increased to$1,403,000 from $797,000, due primarily to increased loan balances in the thirdquarter of 2003 when compared to the same period in 2002. In accordance withSFAS No. 52, “Foreign Currency Translation” (“SFAS 52”), the Company recognizeda foreign currency exchange loss of $1,053,000 related to the TOGA debt to berepaid. Substantially all of the foreign exchange loss relates to intercompanydebt TOGA owed the Company prior to August 15, 2003. As described in Note2 to the Consolidated Financial Statements, the non-permanent portion ofintercompany debt was substantially reduced on August 15, 2003. Thisreduction is expected to substantially reduce future foreign currency gains andlosses.

 

17

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***Results of Operations—Comparison of the Nine Months Ended September 30,2003 and 2002***

 

The Company incurred a netloss of $13,145,000 for the nine months ended September 30, 2003, comparedto a net loss of $4,146,000 for the nine months ended September 30, 2002.The greater net loss for the nine months ended September 30, 2003 isprimarily due to the $5.1 million write-off of deferred financing costsdescribed in Note 2 to the Consolidated Financial Statements and $1.7 millionin additional interest expense due to carrying higher loan balances in 2003.Operating expense increases were caused primarily by increases in theproduction and sale of gas in Australia. Other significant transactions in 2003include a total of $2.4 million in write-downs of oil and gas properties, whichwere substantially offset by a $2.1 million foreign currency gain in 2003related to its Australian operations. In 2002, a gain of $766,000 on a sale ofassets was recognized. The table below provides a comparison of operations forthe nine months ended September 30, 2003 with those of the nine monthsended September 30, 2002. The table is intended to provide a comparativereview of significant operational items and, accordingly, nominal differencesmay exist from the amounts presented in the accompanying financial statements.Certain prior period amounts have been reclassified to ensure comparability.

 
| ** **                                                         | ** ** | **Nine Months Ended  September 30** | ** ** | **Increase** | ** ** | **%Increase**  | ** ** |
|--------------------------------------------------------------------|------------|------------------------------------------|------------|--------------|------------|----------------|------------|
| ** **                                                         | ** ** | **2003**                                 | ** ** | **2002**     | ** ** | **(Decrease)** | ** ** | **(% Decrease)** | ** ** |
| **Worldwide  operations:**                                         |       |                                     |       |         |       |           |       |   |   |
| Operating revenue                                                  |       | $                                        | 4,764,000  |         | $          | 3,574,000      |       | $ | 1,190,000 |   | 33 | % |
| Other  revenue                                                     |       | $                                        | —     |         | $          | 122,000        |       | $ | (122,000 | ) | N/A |   |
| Gas volumes  (Mcf)                                                 |       | 3,332,000                                |       | 2,684,000    |       | 648,000        |       | 24 | % |
| Oil volumes  (Bbls)                                                |       | —                                   |       | 11,000       |       | (11,000        | )          | N/A |   |
| Average gas  price per Mcf                                         |       | $                                        | 1.43       |         | $          | 1.25           |       | $ | 0.18 |   | 14 | % |
| Average oil  price per Bbl                                         |       | —                                   |       | $            | 19.11      |           | (19.11     | ) | N/A |   |
| Operating  expenses                                                |       | $                                        | 3,320,000  |         | $          | 2,130,000      |       | $ | 1,190,000 |   | 56 | % |
| Average  operating cost per Mcf equivalent (“Mcfe”) sold |       | $                                        | 1.00       |         | $          | 0.77           |       | $ | 0.23 |   | 30 | % |
| General and  administrative                                        |       | $                                        | 4,165,000  |         | $          | 3,692,000      |       | $ | 473,000 |   | 13 | % |
| Depreciation,  depletion and amortization (“DD&A”)   |       | $                                        | 1,161,000  |         | $          | 1,124,000      |       | $ | 37,000 |   | 3 | % |
| Write-off of  deferred loan costs                                  |       | $                                        | 5,069,000  |         | $          | —         |       | $ | 5,069,000 |   | N/A |   |
| Interest  expense                                                  |       | $                                        | 3,883,000  |         | $          | 2,191,000      |       | $ | 1,692,000 |   | 77 | % |
|                                                               |       |                                     |       |         |       |           |       |   |   |
| **Australia  operations:**                                         |       |                                     |       |         |       |           |       |   |   |
| Operating  revenue                                                 |       | $                                        | 4,753,000  |         | $          | 3,147,000      |       | $ | 1,606,000 |   | 51 | % |
| Other  revenue                                                     |       | $                                        | —     |         | $          | 120,000        |       | $ | (120,000 | ) | (100 | )% |
| Gas volumes  (Mcf)                                                 |       | 3,330,000                                |       | 2,616,000    |       | 714,000        |       | 27 | % |
| Average gas  price per Mcf                                         |       | $                                        | 1.43       |         | $          | 1.20           |       | $ | 0.23 |   | 19 | % |
| Operating  expenses                                                |       | $                                        | 2,660,000  |         | $          | 1,774,000      |       | $ | 886,000 |   | 50 | % |
| Average  operating cost per Mcf sold                               |       | $                                        | 0.80       |         | $          | 0.68           |       | $ | 0.12 |   | 18 | % |
| Oil and Gas  property DD&A                                     |       | $                                        | 1,070,000  |         | $          | 807,000        |       | $ | 263,000 |   | 33 | % |
| Other  DD&A                                                    |       | $                                        | 53,000     |         | $          | 118,000        |       | $ | (65,000 | ) | (55 | )% |
| Oil and Gas  DD&A rate per Mcf sold                            |       | $                                        | 0.32       |         | $          | 0.31           |       | $ | 0.01 |   | 3 | % |
|                                                               |       |                                     |       |         |       |           |       |   |   |
| **Domestic  operations:**                                          |       |                                     |       |         |       |           |       |   |   |
| Operating  revenue                                                 |       | $                                        | 11,000     |         | $          | 429,000        |       | $ | (418,000 | ) | N/A |   |
| Gas volumes  (Mcf)                                                 |       | 2,000                                    |       | 68,000       |       | (66,000        | )          | N/A |   |
| Oil volumes  (Bbls)                                                |       | —                                   |       | 11,000       |       | (11,000        | )          | N/A |   |
| Average gas  price per Mcf                                         |       | $                                        | 3.99       |         | $          | 3.11           |       | $ | 0.88 |   | 28 | % |
| Average oil  price per Bbl                                         |       | $                                        | —     |         | $          | 19.11          |       | (19.11 | ) | N/A |   |
| Operating  expenses                                                |       | $                                        | 660,000    |         | $          | 356,000        |       | $ | 304,000 |   | 85 | % |
| Average  operating cost per Mcfe sold                              |       | $                                        | 330.00     |         | $          | 2.49           |       | 327.51 |   | 13,153 | % |
| Oil and Gas  property DD&A                                     |       | $                                        | —     |         | $          | 163,000        |       | $ | (163,000 | ) | N/A |   |
| Other  DD&A                                                    |       | $                                        | 38,000     |         | $          | 36,000         |       | $ | 2,000 |   | 6 | % |
| Oil and Gas  DD&A rate per Mcfe sold                           |       | —                                   |       | $            | 1.22       |           | (1.22      | ) | N/A |   |

 

The following narrative should be read inconjunction with the above table

 

18

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Revenues and Sales Volumes

 

Gas volumes sold inAustralia increased 27% due to increased gas sales from existing wells, newwells drilled and an increase in gas deliveries. Gas revenues in Australiaincreased by 51% due to the increase in sales volumes, an increase in theaverage sales price received and changes in exchange rates. The Company’s gassales contracts in Australia are long-term fixed price contracts with yearlyadjustments for inflation. The 19% increase in average gas sales price inAustralia is due primarily to an approximate 13% increase in the value of theAustralian dollar in relation to the U.S. dollar and inflation adjustments.

 

During the first nine monthsof 2003, the Company had minimal domestic revenue. Domestic revenues andvolumes in 2002 relate to the West Buna field which the Company sold in thesecond quarter of 2002.

 

Costs and Expenses

 

Operating expenses inAustralia increased 50% due to an increase in the number of producing wells,increased costs associated with delivering increasing gas volumes and anapproximate 13% decrease in the value of the U.S. dollar in relation to the Australiandollar. Operating expenses also increased due to the Company’s increase in ownershipin the Comet Ridge project in mid-2002. Average operating cost per Mcf soldincreased 18% to $0.80 for the nine months ended September 30, 2003. Ifthe field were selling gas at the field’s current production and compressioncapacity, management estimates operating cost per Mcf would approximate $0.40.A 33% increase in Australian oil and gas property DD&A expense isattributed primarily to higher production volumes and an increase in thedepletion rate. Higher finding costs for reserves added is the principal factorincreasing the depletion rate.

 

Domestic operating expensesin the first nine months of 2003 are largely attributable to the Lay Creek coalbed methane project where the initial ten wells are in the early dewateringphase. Without these Lay Creek operating expenses, the average domesticoperating cost per Mcf sold would be reduced substantially to $6.00 per Mcf.Operating expenses in the first nine months of 2002 include expenses from theWest Buna field. Domestic DD&A expenses decreased due to the aforementionedsale of the Company’s West Buna field.

 

General and administrative (“G&A”)expenses for the first nine months of 2003 increased 13% when compared to thenine months ended September 30, 2002. For the first nine months of 2003,increased G&A costs are principally attributed to assuming operations atComet Ridge.

 

Other Income (Expense)

 

In the third quarter of 2003the Company wrote off $5,069,000 in deferred loan costs related to the TCW loanwhich was retired on August 15, 2003. Interest expense increased to$3,883,000 from $2,191,000 due primarily to increased loan balances in thefirst nine months of 2003 when compared to the same period in 2002. Inaccordance with SFAS No. 52, “Foreign Currency Translation” (“SFAS 52”), theCompany recognized a foreign currency exchange gain of $2,060,000 related tothe TOGA debt to be repaid. Substantially all of this foreign exchange gainrelates to intercompany debt TOGA owed the Company prior to August 15,2003. As described in Note 2 to the Consolidated Financial Statements, thenon-permanent portion of intercompany debt was substantially reduced on August 15,2003. This reduction is expected to substantially reduce future foreigncurrency gains and losses.

 

**Item 4.Controls and Procedures**

 

As of the end of the periodcovered by this report, we evaluated, under the supervision and with theparticipation of our management, including our Chief Executive Officer andChief Financial Officer, the effectiveness of the design and operation of ourdisclosure controls and procedures over financial reporting pursuant to Rule13a-15 and 15d-15 of the Securities Exchange Act of 1934. Based upon thatevaluation, our Chief Executive Officer and our Chief Financial Officerconcluded that our disclosure controls and procedures over financial reportingare adequate and effective at the reasonable assurance level in timely alertingthem to material information required to be included in this quarterly reporton Form 10-Q.

 

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Disclosure controls andprocedures, no matter how well designed and implemented, can provide onlyreasonable assurance of achieving an entity’s disclosure objectives. Thelikelihood of achieving such objectives is affected by limitations inherent in disclosurecontrols and procedures. These limitations include the fact that human judgmentin decision-making can be faulty and that breakdowns in internal control canoccur because of human failures such as simple errors or mistakes or because ofintentional circumvention of the established process.

 

During the period covered bythis report, there have been no changes in our internal controls over financialreporting or in other factors, which could significantly affect internalcontrols over financial reporting, including any corrective actions with regardto significant deficiencies or material weaknesses.

 

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**PART II –OTHER INFORMATION**

 

Item 1. Legal Proceedings

 

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

 

Item 6. Exhibits and Reports on Form 8-K

 

(a) Exhibits:

 

11.           Computation of per share earnings, filed herewith as Note 4 to theConsolidated Financial Statements.

 

10.98       Fifth Amendment to Gas Sales Agreement between Tipperary Oil & Gas(Australia) Pty ltd (ACN 077 536 871) as Seller and Queensland FertilizerAssets Limited (ACN 011 062 294) as Buyer, dated June 30, 2003.Confidential portions of this agreement noted by an “*” have been omitted andfiled separately with the Securities and Exchange Commission pursuant to arequest for confidentiality under Rule 24b-2 of the Securities Exchange Act of1934.

 

31.1         Certification of Chief Executive Officer under Section 302 of theSarbanes-Oxley Act of 2002.

 

31.2         Certification of Chief Financial Officer under Section 302 of theSarbanes-Oxley Act of 2002.

 

32.1         Certification of Chief Executive Officer of Tipperary CorporationPursuant to 18 U.S.C. §1350.

 

32.2         Certification of Chief Financial Officer of Tipperary CorporationPursuant to 18 U.S.C. §1350.

 

Theother material contracts of the Company are incorporated herein by referencefrom the exhibit list in the Company’s Annual Report on Form 10-KSB for theyear ended December 31, 2002.

 

(b) Reports on Form 8-K:

 

TheRegistrant submitted a Form 8-K on August 19, 2003, under Item 12 wherebyit furnished its earnings press release announcing second quarter 2003financial results.

 

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**SIGNATURES**

 

Pursuantto the requirements of the Securities Exchange Act of 1934, the Registrant hasduly caused this report to be signed on its behalf by the undersigned thereuntoduly authorized.

 

 
|                                          | Tipperary Corporation |
|-----------------------------------------------|-----------------------|
|                                          | Registrant            |
|                                          |                  |
| Date:   December 10, 2004 | By:                   |    /s/  David L. Bradshaw |
|                                          |                  |    David L.  Bradshaw, President, Chief Executive Officer |
|                                          |                  |    and  Chairman of the Board of Directors |
|                                          |                  |
|                                          |                  |
| Date:   December 10, 2004 | By:                   |    /s/  Joseph B. Feiten |
|                                          |                  |    Joseph  B. Feiten, Chief Financial Officer and |
|                                          |                  |    Principal  Accounting Officer |

 

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**EXHIBITINDEX**

 

11.           Computation of per share earnings, filedherewith as Note 4 to the Consolidated Financial Statements.

 

10.98       Fifth Amendment to Gas Sales Agreementbetween Tipperary Oil & Gas (Australia) Pty ltd (ACN 077 536 871) as Sellerand Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated June 30,2003. Confidential portions of this agreement noted by an “*” have been omittedand filed separately with the Securities and Exchange Commission pursuant to arequest for confidentiality under Rule 24b-2 of the Securities Exchange Act of1934.

 

31.1         Certification of Chief Executive Officerunder Section 302 of the Sarbanes-Oxley Act of 2002.

 

31.2         Certification of Chief Financial Officerunder Section 302 of the Sarbanes-Oxley Act of 2002.

 

32.1         Certification of Chief Executive Officer ofTipperary Corporation Pursuant to 18 U.S.C. §1350.

 

32.2         Certification of Chief Financial Officer ofTipperary Corporation Pursuant to 18 U.S.C. §1350.

 

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