** **

**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**Washington,D. C. 20549**

# ** **

# **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 June 30, 2004**                                                                                                                                                                                                                                                                                             |
|       |
| **OR**     |
|       |
| **o**      | ** ** | **TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE  SECURITIES EXCHANGE ACT OF 1934**                                                                                                                                                                                                                                                  |
|       |
|       |       | **For  the transition period from                                                   to** |

 

**CommissionFile Number 1-7796**

 

**TIPPERARY CORPORATION**

(Exact name ofregistrant 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’stelephone number)

 

Check whether the issuer(1) filed all reports required to be filed by Section 13 or 15(d) of theExchange Act of 1934 during the past 12 months (or for such shorter period thatthe registrant was required to file such reports), and (2) has been subject tosuch filing 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 ofshares outstanding of each of the issuer’s classes of common stock, as of thelatest practicable date.

 
| **Class**                     | ** ** | **Outstanding at August 11, 2004** |
|-------------------------------|------------|-----------------------------------------|
| Common Stock, $.02 par  value |       | 39,333,989  shares                      |

 

 

----

 

**TIPPERARYCORPORATION AND SUBSIDIARIES**

 

Index to Form 10-Q/A

 
| EXPLANATORY  NOTE |                  |
|-------------------|-----------------------|
|              |                  |   |
| PART I.           | FINANCIAL INFORMATION |   |
|              |                  |   |
|              | Item 1.               | Financial Statements |   |
|              |                  |   |   |
|              |                  | Consolidated Balance Sheets  June 30, 2004 and December 31, 2003 |   |
|              |                  |   |   |
|              |                  | Consolidated  Statements of Operations  Three and six months ended June 30, 2004 and 2003 |   |
|              |                  |   |   |
|              |                  | Consolidated  Statements of Stockholders’ Equity  Six months ended June 30, 2004 and 2003 |   |
|              |                  |   |   |
|              |                  | Consolidated  Statements of Cash Flows  Six months ended June 30, 2004 and 2003 |   |
|              |                  |   |   |
|              |                  | Notes to  Consolidated Financial Statements |   |
|              |                  |   |   |
|              | Item 2.               | Management’s Discussion and Analysis of  Financial Condition and Results of Operations |   |
|              |                  |   |   |
|              | Item 3.               | Quantitative and Qualitative Disclosure About  Market Risk |   |
|              |                  |   |   |
|              | Item 4.               | Controls and Procedures |   |
|              |                  |   |   |
| PART II.          | OTHER INFORMATION     |   |
|              |                  |   |
|              | Item 1.               | Legal  Proceedings |   |
|              |                  |   |   |
|              | Item  2.              | Changes  in Securities |   |
|              |                  |   |   |
|              | Item  4.              | Submission  of Matters to a Vote of Security Holders |   |
|              |                  |   |   |
|              | Item 6.               | Exhibits and Reports on Form 8-K |   |
|              |                  |   |   |
| SIGNATURES        |                  |
|              |                  |
| EXHIBIT INDEX     |                  |

 

# ****

 

EXPLANATORY NOTE

 

This Amendment No. 1 on Form 10-Q is being filed to amend Part I Item4. of the Company’s Quarterly Report on Form 10-Q for the quarterly periodended June 30, 2004, filed on August 16, 2004 (the “Original 10-Q”).  This Amendment No. 1 does not otherwise alterthe disclosures set forth in the Original 10-Q and does not reflect eventsoccurring after the filing of the Original 10-Q.  This Amendment No. 1 is effective for allpurposes as of the date of the filing of the Original 10-Q.

 

----

 

# **PART I** - FINANCIAL INFORMATION

 

**Item 1****.  Financial Statements**

 

**TIPPERARY CORPORATION AND SUBSIDIARIES**

Consolidated Balance Sheets

($ in thousands except per share data)

(unaudited)

 
| ** **                                                                                                                                                                                                                 | ** ** | **June 30,  2004** | ** ** | **December 31,  2003** | ** ** |
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------------|------------|-----------------------------|------------|
|                                                                                                                                                                                                                       |       |                    |       |                        |       |
| ASSETS                                                                                                                                                                                                                     |       |                    |       |                        |       |
| Current  assets:                                                                                                                                                                                                           |       |                    |       |                        |       |
| Cash  and cash equivalents                                                                                                                                                                                                 |       | $                       | 1,568      |                        | $          | 2,996 |   |
| Receivables                                                                                                                                                                                                                |       | 1,488                   |       | 1,585                       |       |
| Other  current assets                                                                                                                                                                                                      |       | 185                     |       | 344                         |       |
| Total  current assets                                                                                                                                                                                                      |       | 3,241                   |       | 4,925                       |       |
|                                                                                                                                                                                                                       |       |                    |       |                        |       |
| Property,  plant and equipment, at cost:                                                                                                                                                                                   |       |                    |       |                        |       |
| Oil  and gas properties, full cost method                                                                                                                                                                                  |       | 120,720                 |       | 120,703                     |       |
| Other  property and equipment                                                                                                                                                                                              |       | 4,353                   |       | 4,431                       |       |
|                                                                                                                                                                                                                       |       | 125,073                 |       | 125,134                     |       |
|                                                                                                                                                                                                                       |       |                    |       |                        |       |
| Less  accumulated depreciation, depletion and amortization                                                                                                                                                                 |       | (8,170                  | )          | (8,078                      | )          |
| Property,  plant and equipment, net                                                                                                                                                                                        |       | 116,903                 |       | 117,056                     |       |
|                                                                                                                                                                                                                       |       |                    |       |                        |       |
| Deferred  loan costs                                                                                                                                                                                                       |       | 4,060                   |       | 1,140                       |       |
| Other  noncurrent assets                                                                                                                                                                                                   |       | 459                     |       | 487                         |       |
|                                                                                                                                                                                                                       |       | $                       | 124,663    |                        | $          | 123,608 |   |
|                                                                                                                                                                                                                       |       |                    |       |                        |       |
| LIABILITIES  AND STOCKHOLDERS’ EQUITY                                                                                                                                                                                 |       |                    |       |                        |       |
| Current  liabilities:                                                                                                                                                                                                      |       |                    |       |                        |       |
| Current  portion of long-term debt                                                                                                                                                                                         |       | $                       | 4,000      |                        | $          | — |   |
| Accounts  payable                                                                                                                                                                                                          |       | 1,973                   |       | 1,883                       |       |
| Accrued  liabilities                                                                                                                                                                                                       |       | 1,493                   |       | 2,329                       |       |
| Royalties  payable                                                                                                                                                                                                         |       | 77                      |       | 75                          |       |
| Total  current liabilities                                                                                                                                                                                                 |       | 7,543                   |       | 4,287                       |       |
|                                                                                                                                                                                                                       |       |                    |       |                        |       |
| Long-term  debt, net of current portion                                                                                                                                                                                    |       | 82,456                  |       | 74,126                      |       |
| Long-term  asset retirement obligation                                                                                                                                                                                     |       | 304                     |       | 268                         |       |
| Commitments  and contingencies (Note 5)                                                                                                                                                                                    |       |                    |       |                        |       |
| Minority  interest                                                                                                                                                                                                         |       | —                  |       | 418                         |       |
|                                                                                                                                                                                                                       |       |                    |       |                        |       |
| 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; 39,336,087 and  39,231,087 shares issued, and 39,326,489 and 39,221,489 shares outstanding as  of June 30, 2004 and December 31, 2003, respectively |       | 787                     |       | 785                         |       |
| Capital  in excess of par value                                                                                                                                                                                            |       | 150,321                 |       | 149,970                     |       |
| Accumulated  deficit                                                                                                                                                                                                       |       | (121,272                | )          | (113,315                    | )          |
| Accumulated  other comprehensive income                                                                                                                                                                                    |       | 4,549                   |       | 7,094                       |       |
| Treasury  stock, at cost; 9,598 shares                                                                                                                                                                                     |       | (25                     | )          | (25                         | )          |
| Total  stockholders’ equity                                                                                                                                                                                           |       | 34,360                  |       | 44,509                      |       |
|                                                                                                                                                                                                                       |       | $                       | 124,663    |                        | $          | 123,608 |   |

# ** **

See accompanying notes to Consolidated Financial Statements.

 

1

----

 

# **TIPPERARY CORPORATION AND SUBSIDIARIES**

Consolidated Statements of Operations

(in thousands,except per share data)

(unaudited)

 
| ** **                                                                | ** ** | **Three months ended  June 30,** | ** ** | **Six months ended  June 30,** | ** ** |
|---------------------------------------------------------------------------|------------|---------------------------------------|------------|-------------------------------------|------------|
| **2004**                                                                  | ** ** | **2003**                              | ** ** | **2004**                            | ** ** | **2003** | ** ** |
|                                                                      |       |                                  |       |                                |       |   |   |   |   |
| Revenues                                                                  |       | $                                     | 1,562      |                                | $          | 1,709 |   | $ | 2,730 |   | $ | 3,050 |   |
| Costs  and expenses:                                                      |       |                                  |       |                                |       |   |   |   |   |
| Operating                                                                 |       | 1,247                                 |       | 1,111                               |       | 2,641 |   | 2,068 |   |
| Depreciation,  depletion and amortization                                 |       | 356                                   |       | 398                                 |       | 607 |   | 706 |   |
| Asset  retirement obligation accretion                                    |       | 9                                     |       | 6                                   |       | 18 |   | 12 |   |
| Impairment  of oil and gas properties                                     |       | —                                |       | 2,221                               |       | 150 |   | 2,221 |   |
| General  and administrative                                               |       | 1,510                                 |       | 1,291                               |       | 3,554 |   | 2,812 |   |
| Total  costs and expenses                                                 |       | 3,122                                 |       | 5,027                               |       | 6,970 |   | 7,819 |   |
| Operating  loss                                                           |       | (1,560                                | )          | (3,318                              | )          | (4,240 | ) | (4,769 | ) |
|                                                                      |       |                                  |       |                                |       |   |   |   |   |
| Other  income (expense):                                                  |       |                                  |       |                                |       |   |   |   |   |
| Interest  and other income                                                |       | 69                                    |       | 15                                  |       | 107 |   | 22 |   |
| Interest  expense                                                         |       | (2,097                                | )          | (1,175                              | )          | (4,233 | ) | (2,480 | ) |
| Foreign  currency exchange gain (loss)                                    |       | (6                                    | )          | 3,117                               |       | (9 | ) | 3,113 |   |
| Total  other income (expense)                                             |       | (2,034                                | )          | 1,957                               |       | (4,135 | ) | 655 |   |
| Loss  before income taxes                                                 |       | (3,594                                | )          | (1,361                              | )          | (8,375 | ) | (4,114 | ) |
|                                                                      |       |                                  |       |                                |       |   |   |   |   |
| Income  tax benefit                                                       |       | —                                |       | —                              |       | — |   | — |   |
| Loss  before minority interest and cumulative effect of accounting change |       | (3,594                                | )          | (1,361                              | )          | (8,375 | ) | (4,114 | ) |
|                                                                      |       |                                  |       |                                |       |   |   |   |   |
| Minority  interest in loss (income) of subsidiary                         |       | 63                                    |       | (265                                | )          | 418 |   | (181 | ) |
| Loss  before cumulative effect of accounting change                       |       | (3,531                                | )          | (1,626                              | )          | (7,957 | ) | (4,295 | ) |
|                                                                      |       |                                  |       |                                |       |   |   |   |   |
| Cumulative  effect of accounting change                                   |       | —                                |       | —                              |       | — |   | (46 | ) |
| Net  loss                                                                 |       | $                                     | (3,531     | )                                   | $          | (1,626 | ) | $ | (7,957 | ) | $ | (4,341 | ) |
|                                                                      |       |                                  |       |                                |       |   |   |   |   |
| Net  loss per share basic and diluted                                     |       | $                                     | (.09       | )                                   | $          | (.04 | ) | $ | (.20 | ) | $ | (.11 | ) |
| Weighted  average shares outstanding basic and diluted                    |       | 39,325                                |       | 39,221                              |       | 39,308 |   | 39,221 |   |

 

See accompanying notes toConsolidated Financial Statements.

 

2

----

 

**TIPPERARY CORPORATION ANDSUBSIDIARIES**

**ConsolidatedStatement of Stockholders’ Equity(Unaudited)**

**For the Six Months EndedJune 30, 2003 and 2004**

**(in thousands)**

 
| ** **                               | ** ** | ** **    | ** **      | ** **        | ** **         | ** ** | ** ** | **Accumulated** | ** ** | ** ** | ** ** | ** ** | ** ** |
|------------------------------------------|------------|---------------|-----------------|-------------------|--------------------|------------|------------|-----------------|------------|------------|------------|------------|------------|
| **Capital in**                           | ** ** | **Other**     | ** **      |
| **Common Stock**                         | ** ** | **excess of** | **Accumulated** | **Comprehensive** | **Treasury Stock** | ** ** | ** ** |
| **Shares**                               | ** ** | **Amount**    | ** **      | **par value**     | **Deficit**        | **Income** | **Shares** | ** **      | **Amount** | ** ** | **Total**  |
| Balance  at December 31, 2002       |       | 39,221        |            | $                 | 785                |       | $          | 149,953         |       | $          | (97,946)   |       | —     |   | 10 |   | $ | (25) |   | $ | 52,767 |   |
|                                     |       |          |            |              |               |       |       |            |       |       |       |       |       |   |   |   |   |
| Net  loss                                |       | —        |            | —            |               | —     |       | (4,341          | )          | —     |       | —     |       | — |   | (4,341 | ) |
| Other  comprehensive income:             |       |          |            |              |               |       |       |            |       |       |       |       |       |   |   |   |   |
| Foreign  currency translation adjustment |       | —        |            | —            |               | —     |       | —          |       | 3,804      |       | —     |       | — |   | 3,804 |   |
| Comprehensive  loss                      |       |          |            |              |               |       |       |            |       |       |       |       |       |   |   | (537 | ) |
| Compensatory  warrants granted           |       | —        |            | —            |               | 14         |       | —          |       | —     |       | —     |       | — |   | 14 |   |
|                                     |       |          |            |              |               |       |       |            |       |       |       |       |       |   |   |   |   |
| Balance  at June 30, 2003           |       | 39,221        |            | $                 | 785                |       | $          | 149,967         |       | $          | (102,287   | )          | $          | 3,804 |   | 10 |   | $ | (25 | ) | $ | 52,244 |   |
|                                     |       |          |            |              |               |       |       |            |       |       |       |       |       |   |   |   |   |
| Balance  at December 31, 2003       |       | 39,221        |            | $                 | 785                |       | $          | 149,970         |       | $          | (113,315   | )          | $          | 7,094 |   | 10 |   | $ | (25 | ) | $ | 44,509 |   |
|                                     |       |          |            |              |               |       |       |            |       |       |       |       |       |   |   |   |   |
| Net  loss                                |       | —        |            | —            |               | —     |       | (7,957          | )          | —     |       | —     |       | — |   | (7,957 | ) |
| Other  comprehensive loss:               |       |          |            |              |               |       |       |            |       |       |       |       |       |   |   |   |   |
| Foreign  currency Translation adjustment |       | —        |            | —            |               | —     |       | —          |       | (2,545     | )          | —     |       | — |   | (2,545 | ) |
| Comprehensive  loss                      |       |          |            |              |               |       |       |            |       |       |       |       |       |   |   | (10,502 | ) |
| Compensatory  warrants granted           |       | —        |            | —            |               | 66         |       | —          |       | —     |       | —     |       | — |   | 66 |   |
| Stock  options exercise                  |       | 105           |            | 2                 |               | 285        |       | —          |       | —     |       | —     |       | — |   | 287 |   |
| Balance  at June 30, 2004           |       | 39,326        |            | $                 | 787                |       | $          | 150,321         |       | $          | (121,272   | )          | $          | 4,549 |   | 10 |   | $ | (25 | ) | $ | 34,360 |

# ** **

See accompanying notes to Consolidated Financial Statements.

 

3

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# **TIPPERARY CORPORATION AND SUBSIDIARIES**

Consolidated Statements of Cash Flows

(in thousands)

(unaudited)

 
| ** **                                                                   | ** ** | **Six months ended****June 30,** | ** ** |
|------------------------------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                                                   | **2004**   | ** **                            | **2003**   | ** ** |
|                                                                         |       |                                  |       |   |   |
| Cash  flows from operating activities:                                       |       |                                  |       |   |   |
| Net  loss                                                                    |       | $                                     | (7,957     | ) | $ | (4,341 | ) |
| Adjustments  to reconcile net loss to net cash used in operating activities: |       |                                  |       |   |   |
| Depreciation,  depletion and amortization                                    |       | 607                                   |       | 706 |   |
| Amortization  of deferred loan costs                                         |       | 197                                   |       | 708 |   |
| Compensatory  warrants granted                                               |       | 66                                    |       | 4 |   |
| Minority  interest in (loss) income of subsidiary                            |       | (418                                  | )          | 181 |   |
| Asset  retirement obligation accretion                                       |       | 18                                    |       | 12 |   |
| Cumulative  effect of accounting change                                      |       | —                                |       | 46 |   |
| Impairment  of oil and gas properties                                        |       | 150                                   |       | 2,221 |   |
| Foreign  currency exchange gain                                              |       | —                                |       | (3,113 | ) |
| Changes  in current assets and current liabilities:                          |       |                                  |       |   |   |
| Decrease  (increase) in receivables                                          |       | 241                                   |       | (710 | ) |
| Decrease  in other current assets                                            |       | 120                                   |       | 180 |   |
| (Decrease)  increase in accounts payable and accrued liabilities             |       | (149                                  | )          | 1,005 |   |
| Decrease  in royalties payable                                               |       | 2                                     |       | 14 |   |
| Net  cash used in operating activities                                       |       | (7,123                                | )          | (3,087 | ) |
|                                                                         |       |                                  |       |   |   |
| Cash  flows from investing activities:                                       |       |                                  |       |   |   |
| Capital  expenditures                                                        |       | (9,431                                | )          | (11,982 | ) |
| Net  cash used in investing activities                                       |       | (9,431                                | )          | (11,982 | ) |
|                                                                         |       |                                  |       |   |   |
| Cash  flows from financing activities:                                       |       |                                  |       |   |   |
| Proceeds  from issuance of common stock on exercise of options               |       | 287                                   |       | — |   |
| Proceeds  from borrowings                                                    |       | 86,436                                |       | 19,705 |   |
| Principal  repayments                                                        |       | (68,190                               | )          | (4,940 | ) |
| Decrease  in restricted cash                                                 |       | —                                |       | 394 |   |
| Payments  for deferred loan costs                                            |       | (3,313                                | )          | (90 | ) |
| Net  cash provided by financing activities                                   |       | 15,220                                |       | 15,069 |   |
|                                                                         |       |                                  |       |   |   |
| Effect  of exchange rate changes on cash                                     |       | (94                                   | )          | 221 |   |
|                                                                         |       |                                  |       |   |   |
| Net  increase (decrease) in cash and cash equivalents                        |       | (1,428                                | )          | 221 |   |
|                                                                         |       |                                  |       |   |   |
| Cash  and cash equivalents at beginning of period                            |       | 2,996                                 |       | 1,725 |   |
|                                                                         |       |                                  |       |   |   |
| Cash  and cash equivalents at end of period                                  |       | $                                     | 1,568      |   | $ | 1,946 |   |

 

See accompanying notes to Consolidated Financial Statements.

 

4

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**TIPPERARYCORPORATION AND SUBSIDIARIES**

**NOTES TOCONSOLIDATED FINANCIAL STATEMENTS**

**(Unaudited)**

 

**NOTE 1 –OPERATIONS AND 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 June 30, 2004, and theresults of their operations for the three-month and six-month periods endedJune 30, 2004 and 2003 and their cash flows for the six-month periodsended June 30, 2004 and 2003. The Consolidated Financial Statementsinclude the accounts of Tipperary Corporation and its wholly-ownedsubsidiaries, Tipperary Oil and Gas Corporation, Tipperary CSG Inc. and BurroPipeline Corporation, and its 90%-owned subsidiary, Tipperary Oil and Gas(Australia) Pty Ltd (“TOGA”).  Allintercompany balances have been eliminated. The accounting policies followed by the Company are included in Note 1to the Consolidated Financial Statements in its Annual Report on Form 10-K forthe year ended December 31, 2003. These financial statements should be read in conjunction with the Form10-K.

 

New AccountingPronouncements

 

The Company has reviewedall recently issued, but not yet adopted, accounting pronouncements andstandards to determine their effects, if any, on its results of operations orfinancial position.  Based on its review,the Company believes that none of these pronouncements will have a significanteffect on its current or future financial position or results of operations.

 

## Asset RetirementObligations

 

On January 1, 2003,the Company adopted Statement of Financial Accounting Standards No. 143, “Accountingfor Asset Retirement Obligations” (“SFAS No. 143”), which provides accountingrequirements for retirement obligations associated with tangible long-livedassets, including the timing of liability recognition, initial measurement ofthe liability, allocation of asset retirement costs to expense, subsequentmeasurement of the liability, and financial statement disclosures.  SFAS No. 143 requires that asset retirementcosts be capitalized along with the cost of the related long-lived asset.  The asset retirement costs should then beallocated to expense using a systematic and rational method.  The Company has determined that it has assetretirement costs associated with wells drilled in Australia and the United States.The Company also expects to incur retirement costs to dismantle two gascompression plant facilities located in Australia. The following table setsforth the changes in the asset retirement obligations:

 

                                    
| **(in thousands)**                                               | ** ** | ** ** | ** ** |
|------------------------------------------------------------------|------------|------------|------------|
| Beginning  asset retirement obligation at December 31, 2003 |       | $          | 268        |   |
| Asset  retirement obligation accretion                           |       | 18         |       |
| Asset  retirement obligation additions                           |       | 18         |       |
| Payments  on asset retirement obligation                         |       | —     |       |
| Ending  asset retirement obligation at June 30, 2004        |       | $          | 304        |   |

 

Business Combinations andGoodwill and Intangible Assets

 

In June 2001, theFASB issued SFAS No. 141, “Business Combinations” (“SFAS No. 141”)and SFAS No. 142, “Goodwill and Intangible Assets” (“SFAS No. 142”).SFAS Nos. 141 and 142 became effective on July 1, 2001 andJanuary 1, 2002, respectively. SFAS No. 141 requires all businesscombinations initiated after June 30, 2001 to be accounted for using thepurchase method. Additionally, SFAS No. 141 requires companies todisaggregate and report separately from goodwill certain intangibleassets.  SFAS No. 142 establishesnew guidelines for accounting for goodwill and other intangible assets. UnderSFAS No. 142, goodwill and certain other intangible assets are not amortized,but rather are reviewed annually for impairment. One interpretation that wasconsidered relative to these standards was that oil and gas mineral rights heldunder 

 

5

----

 

lease and othercontractual arrangements representing the right to extract such reserves forboth undeveloped and developed leaseholds should be classified separately fromoil and gas properties, as intangible assets on the Company’s consolidatedbalance sheets.  In April 2004, theFinancial Accounting Standards Board amended SFAS Nos. 141 and 142 andclarified the interpretation by defining mineral rights, such as oil and gasmineral rights, as tangible assets. Accordingly, the guidelines for accounting for intangible assets asprovided in SFAS No. 142 would not apply to oil and gas mineral rights.  In accordance with this new guideline, theCompany will continue to classify its contractual rights to extract oil and gasreserves as tangible oil and gas properties.

 

Stock-Based Compensation

 

SFAS Nos. 148 and No. 123encourage, but do not require, companies to record the compensation cost forstock-based employee compensation plans at fair value.  At June 30, 2004, the Company had twostock-based employee option plans and warrants issued to directors andemployees.  The Company has chosen tocontinue to account for stock-based compensation using the intrinsic valuemethod prescribed in Accounting Principles Board Opinion No. 25, “Accountingfor Stock Issued to Employees,” (“APB 25”) and has applied the disclosureprovisions of SFAS Nos. 123 and 148. Accordingly, compensation cost for fixed stock options and warrants ismeasured as the excess, if any, of the quoted market price of the Company’sstock at the date of the grant over the amount an employee must pay to acquirethe stock.  Pro forma disclosures as ifthe Company had adopted the cost recognition provisions of SFAS Nos. 148 and123 are presented below:

 
| ** **                                                                                       | ** ** | **Six Months Ended June 30,**        | ** ** |
|--------------------------------------------------------------------------------------------------|------------|-------------------------------------------|------------|
| ** **                                                                                       | ** ** | **2004**                                  | ** ** | **2003** | ** ** |
| ** **                                                                                       | ** ** | **(in thousands, except per share data)** | ** ** |
|                                                                                             |       |                                      |       |   |   |
| Net  loss, as reported                                                                           |       | $                                         | (7,957     | ) | $ | (4,341 | ) |
| Add:                                                                                             |       |                                      |       |   |   |
| Total  compensation cost included in reported net loss, net of $0 tax                            |       | —                                    |       | — |   |
| Deduct:                                                                                          |       |                                      |       |   |   |
| Total  compensation cost determined under fair value based method for all awards,  net of $0 tax |       | (29                                       | )          | (73 | ) |
|                                                                                             |       |                                      |       |   |   |
| Pro  forma net loss                                                                              |       | $                                         | (7,986     | ) | $ | (4,414 | ) |
| Loss  per share                                                                                  |       |                                      |       |   |   |
| Basic  and diluted—as reported                                                              |       | $                                         | (.20       | ) | $ | (.11 | ) |
| Basic  and diluted—pro forma                                                                |       | $                                         | (.20       | ) | $ | (.11 | ) |

 
| ** **                                                                                       | ** ** | **Three Months Ended June 30,**      | ** ** |
|--------------------------------------------------------------------------------------------------|------------|-------------------------------------------|------------|
| ** **                                                                                       | ** ** | **2004**                                  | ** ** | **2003** | ** ** |
| ** **                                                                                       | ** ** | **(in thousands, except per share data)** | ** ** |
|                                                                                             |       |                                      |       |   |   |
| Net  loss, as reported                                                                           |       | $                                         | (3,531     | ) | $ | (1,626 | ) |
| Add:                                                                                             |       |                                      |       |   |   |
| Total  compensation cost included in reported net loss, net of $0 tax                            |       | —                                    |       | — |   |
| Deduct:                                                                                          |       |                                      |       |   |   |
| Total  compensation cost determined under fair value based method for all awards,  net of $0 tax |       | (13                                       | )          | (36 | ) |
|                                                                                             |       |                                      |       |   |   |
| Pro  forma net loss                                                                              |       | $                                         | (3,544     | ) | $ | (1,662 | ) |
| Loss  per share                                                                                  |       |                                      |       |   |   |
| Basic  and diluted—as reported                                                              |       | $                                         | (.09       | ) | $ | (.04 | ) |
| Basic  and diluted—pro forma                                                                |       | $                                         | (.09       | ) | $ | (.04 | ) |

 

6

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RevenueRecognition and Gas Imbalances

 

The Company recognizesnatural gas and oil revenue from its interests in producing wells as naturalgas and oil are produced and sold from those wells. The Company uses the salesmethod of accounting for these revenues. Under the sales method, revenues arerecognized based on actual volumes sold to purchasers. With natural gasproduction operations, joint owners may take more or less than the productionvolumes entitled to them under the governing operating agreement. The Companyrecords a natural gas imbalance in other liabilities if its excess takes ofnatural gas exceed its remaining proved reserves for the property.  As of June 30, 2004, the Company hadtaken and sold more than its entitled share of natural gas volumes producedfrom the Comet Ridge project, and was overproduced by approximately 1,701 MMcf(net of royalties). Based on the June 30, 2004 average sales price of$1.62 per Mcf, this overproduction represents approximately $2.8 millionin gas revenues. No liability has been recorded for the excess volumes taken,as they do not exceed the Company’s share of remaining proved reserves. Underthe terms of the governing gas balancing agreement, the Company may be requiredto reduce the monthly volumes it sells by up to 50% of its entitled share of sales,to enable underproduced parties to sell more than their entitled share of thegas sales and cure the imbalance.

 

ForeignCurrency

 

The functional currencyof the Company’s Australian subsidiary, TOGA, is the Australian dollar. As thefunctional currency is the local currency, the current rate method is used totranslate Australian dollar financial statements into U.S. dollars for TOGA.All assets and liabilities are translated using current exchange rates, whilerevenues and expenses are translated at rates in existence when thetransactions occurred. The translation adjustment that results from usingvarying rates in the translation process is reported as a component of othercomprehensive income (loss) and is accumulated and reported as a separate componentof stockholders’ equity in the Company’s Consolidated Financial Statements.

 

The cumulative foreigncurrency translation adjustment (net of $0 tax) as of June 30, 2004 andDecember 31, 2003 totaled $4.5 million and $7.1 million,respectively.

 

#### Liquidity and Operations

 

The Company anticipatesfunding operations and capital expenditures in Australia for the remainder of2004 using funds from a $150 million AUD (approximately $114 million USD)financing facility (see Note 3).

 

The Company anticipates fundingoperations and capital expenditures in the United States for 2004 using (a)cash on hand at June 30, 2004 and (b) a commitment from Slough Estates USAInc. (“Slough”), the Company’s majority shareholder, to provide funds forworking capital, board-approved capital expenditures and operations throughApril 2005.

 

In order to funddiscretionary domestic capital expenditures in 2004 in excess of these cashresources, the Company contemplates that it will require alternative sources ofcapital.  Potential additional sources offunding may include additional debt financings and asset sales.  With the sale of interests in its prospectiveacreage, the Company expects to generate cash to reduce its investment inindividual projects.  However, in theevent that sufficient funding cannot be obtained, the Company will be requiredto curtail planned expenditures and may have to sell additional acreage and/orrelinquish acreage.

 

**NOTE 2 - RELATED PARTYTRANSACTIONS**

 

At June 30, 2004,the Company owed Slough and Slough Trading Estates Limited (“STEL”), a UnitedKingdom company which is the parent of Slough, approximately$15.5 million.

 

As ofJune 30, 2004, the Company had one credit facility agreement withSTEL allowing the Company to borrow on an unsecured basis up to$11.5 million for its U.S. operations. Using borrowings from this credit facility, the Company substantiallyfunded its operating and capital needs in the United States during 2003 andthrough the first half of 2004. The Company may repay the loan in whole or inpart without prepayment penalties.  Thecredit facility bears interest at 13% per annum and is due April 2,2012.  STEL may demand repayment prior tothe maturity date provided that STEL gives 18-

 

7

----

 

months notice. TheCompany is limited in taking on any additional third party indebtedness, eithersecured or unsecured, or making a priority payment in respect of any obligationwithout first obtaining written approval from STEL so long as the STELindebtedness exists. In connection with this credit facility, the Company paidSTEL arrangement fees of $40,000.  TheU.S. dollar values of the outstanding balances of these facilities as ofJune 30, 2004 were $11.5 million.

 

In 2002, the Companyborrowed $4 million from Slough which is evidenced by a note payable thatbears interest at LIBOR plus 3.5% (4.83% as of June 30, 2004) and ispayable in full on April 30, 2005.

 

In December 2003,Slough Estates plc, STEL’s parent, guaranteed for a period up to five years abank credit facility of $150.0 million AUD that closed in June 2004 (SeeNote 3).  As consideration for theguarantee, the Company will pay 1% per annum on the daily outstanding balanceof the debt guaranteed.  As ofJune 30, 2004, the Company had paid guarantee fees of $23,000.

 

In August 2003, TOGAborrowed $29.7 million ($45 million AUD) from STEL for the solepurpose of paying off a $22 million long-term debt owed TCW AssetManagement Company (“TCW”) and to substantially fund a $7.7 million repurchaseof the 6% overriding royalty held by TCW on the Company’s Comet Ridgeproperties.  In addition, TOGA borrowed$55.0 million AUD under a credit facility agreement with STEL to fund itsoperations in Australia.  These loansbear interest at 13% per annum.  Inconnection with these loans, the Company paid arrangement fees of $250,000 USDand $100,000 AUD, respectively, to STEL. These loans were paid in full June 18, 2004 with funds from a bankcredit facility (see Note 3).

 

For the six month periodsended June 30, 2004 and 2003, approximately $4.7 million and $656,000,respectively, in interest and fees were paid collectively to Slough and STELunder the financing agreements discussed herein.

 

**NOTE 3 -OTHER DEBT**

 

On June 9, 2004,TOGA entered into a $150.0 million AUD senior credit facility agreement withAustralia and New Zealand Banking Group Limited and BOS International(Australia) Limited for the purpose of paying in full TOGA’s borrowings of$100.0 million AUD from STEL (see Note 2) and to fund TOGA’s share ofdevelopment costs of the Comet Ridge coalseam gas project in Queensland,Australia.  Funds from the facility areexpected to be available over five years and repayable in variable portionsbeginning in 2007 and concluding in 2014. The interest rate for the facility (6.425% per annum as of June 30,2004) varies with the Australian inter-bank rate plus other factors.  Commitment fees of 0.425% per annum ofcommitted but undrawn funds, as defined in the credit facility, are payablesemi-annually.  The facility iscollateralized by, among other things, TOGA’s common stock and the Company’sconsolidated interest in the Comet Ridge project and is guaranteed for up tofive years by Slough Estates plc (See Note 2). The facility contains certain restrictive covenants, includingmaintenance of certain financial ratios. The U.S. dollar value of the outstanding balance of this facility as ofJune 30, 2004 was approximately $71.0 million ($103.0 million AUD).  TOGA incurred $4.0 million in loan costs whichTOGA has deferred and is amortizing over five years.

 

8

----

 

**NOTE 4 - LOSS PER SHARE**

 

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

              
| ** **                                                                              | ** ** | **Three Months Ended  June 30,** | ** ** |
|-----------------------------------------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                                                              | **2004**   | ** **                            | **2003**   | ** ** |
|                                                                                    |       |                                  |       |   |   |
| Numerator:                                                                              |       |                                  |       |   |   |
|                                                                                    |       |                                  |       |   |   |
| Net  loss                                                                               |       | $                                     | (3,531     | ) | $ | (1,626 | ) |
|                                                                                    |       |                                  |       |   |   |
| Denominator:                                                                            |       |                                  |       |   |   |
| Weighted-average  shares outstanding                                                    |       | 39,325                                |       | 39,221 |   |
| Effect  of dilutive securities:                                                         |       |                                  |       |   |   |
| Assumed  exercise of dilutive options and warrants                                      |       | —                                |       | — |   |
|                                                                                    |       |                                  |       |   |   |
| Weighted-average  shares and dilutive potential common shares                           |       | 39,325                                |       | 39,221 |   |
|                                                                                    |       |                                  |       |   |   |
| Basic  and diluted loss per share                                                       |       | $                                     | (.09       | ) | $ | (.04 | ) |
|                                                                                    |       |                                  |       |   |   |
| Total  options and warrants which could potentially dilute basic EPS in future  periods |       | 3,518                                 |       | 3,573 |   |

 
| ** **                                                                              | ** ** | **Six Months Ended  June 30,** | ** ** |
|-----------------------------------------------------------------------------------------|------------|-------------------------------------|------------|
| **2004**                                                                                | ** ** | **2003**                            | ** ** |
|                                                                                    |       |                                |       |   |   |
| Numerator:                                                                              |       |                                |       |   |   |
|                                                                                    |       |                                |       |   |   |
| Net  loss                                                                               |       | $                                   | (7,957     | ) | $ | (4,341 | ) |
|                                                                                    |       |                                |       |   |   |
| Denominator:                                                                            |       |                                |       |   |   |
| Weighted-average  shares outstanding                                                    |       | 39,308                              |       | 39,221 |   |
| Effect  of dilutive securities:                                                         |       |                                |       |   |   |
| Assumed  exercise of dilutive options and warrants                                      |       | —                              |       | — |   |
|                                                                                    |       |                                |       |   |   |
| Weighted-average  shares and dilutive potential common shares                           |       | 39,308                              |       | 39,221 |   |
|                                                                                    |       |                                |       |   |   |
| Basic  and diluted loss per share                                                       |       | $                                   | (.20       | ) | $ | (.11 | ) |
|                                                                                    |       |                                |       |   |   |
| Total  options and warrants which could potentially dilute basic EPS in future  periods |       | 3,518                               |       | 3,573 |   |

 

9

----

 

**NOTE 5 - COMMITMENTS ANDCONTINGENCIES**

 

The Company, TOGA and twounaffiliated working interest owners are plaintiffs in a lawsuit filed in 1998,styled *Tipperary Corporation and TipperaryOil & Gas (Australia) Pty Ltd v. Tri-Star Petroleum Company,James H. Butler, Sr., and James H. Butler, Jr.*, CauseNo. CV42,265, District Court of Midland County, Texas involving the CometRidge project. The plaintiffs allege, among other matters, that Tri-Star and/orthe individual defendants failed to operate the project in a good andworkmanlike manner and committed various other breaches of a joint operatingcontract, breached a previous mediation agreement, committed certain breachesof fiduciary and other duties owed to the plaintiffs, and committed fraud inconnection with the project.  Tri-Starhas answered the allegations, and filed amended pleadings on April 6,2004, denying liability and raising a number of affirmative defenses.  Tri-Star also amended its counterclaim toinclude claims for various breaches of the joint operating contract by theCompany and TOGA, other breaches of duties, forfeiture of acreage and unjustenrichment.  Tri-Star has also requestedforeclosure of operator’s liens, modification and reformation of the jointoperating contract.  TOGA has operatedthe project since March 2002, after the court entered its Writ of TemporaryInjunction (the “Injunction”) to enforce the votes of a majority-in-interest ofthe parties under the joint operating agreement to remove Tri-Star as operatorand replace it with TOGA.  All availableappeals of the Injunction have been exhausted and TOGA will continue asoperator of the Comet Ridge Project at least through the conclusion of a trialon the merits, and thereafter if it is successful at trial.

 

In June 2002, theDistrict Court ruled as unenforceable the arbitration provisions of theexisting mediation agreement between the parties.  With the exception of a Motion forReconsideration to the Texas Supreme Court which may be filed, all availableappeals of the arbitration issues have been exhausted.  The case is set for trial beginningNovember 2, 2004.

 

On October 1, 2003,the District Court signed an Order finding that Tri-Star willfully disobeyedthe Injunction, ordering Tri-Star to cooperate with the Operator and, amongother things, to execute a power of attorney to allow the Company to dealdirectly with the surface owners and governmental authorities on matterspertaining to the Comet Ridge Project. Tri-Star filed objections to the powerof attorney. In January 2004, the District Court conducted a show causehearing to determine whether sanctions for Tri-Star’s past violations of theInjunction, and conditional sanctions to deter future violations, should beimposed and heard a Tri-Star motion to increase the amount of the bond securingthe injunction from $500,000 to $1.0 million and objections to the powerof attorney.  On March 8, 2004, the DistrictCourt ruled that the bond will not be increased and denied Tri-Star’sobjections.  The District Court hasawarded $283,631 in sanctions against Tri-Star, payable upon finaljudgment.  Tri-Star unsuccessfullyappealed the October 2003 ruling to the Eighth District Court of Appeals,and then filed a Petition for Review and Petition for Writ of Mandamus in theTexas Supreme Court.  The Company filedresponse briefs and requested sanctions against Tri-Star.  Hearing the case is discretionary in theTexas Supreme Court, and the Court has made no decision, at this time, onwhether to accept review.

 

If the District Courtagrees that amounts billed to the Company were improper, then upon recoveryfrom the defendants, the Company will reduce its full cost pool forapproximately $1.0 million of recovered capital costs and will record a gain ofapproximately $200,000 for recovered operating costs.

 

10

----

 

 

**NOTE 6 - OPERATIONS BY GEOGRAPHICAREA**

 

Segment information hasbeen prepared in accordance with SFAS No. 131, “Disclosures About Segments ofan Enterprise and Related Information.” The Company has two geographic reporting segments, Australia and theUnited States, within the oil and gas exploration, development and productionindustry.  General and administrativeexpenses, interest expense and interest and other income are not allocated tosegments.  The segment data presentedbelow was prepared on the same basis as the Consolidated FinancialStatements.  Reportable business segmentinformation as of June 30, 2004 and 2003 and for the three and six monthsended June 30, 2004 and 2003 is as follows (in thousands):

 

**As of and for the three monthsended June 30, 2004**

 
| ** **                          | ** ** | **Gas and Oil Operations** | ** ** | **Non-**   | ** ** | ** ** | ** ** |
|-------------------------------------|------------|----------------------------|------------|------------|------------|------------|------------|
| ** **                          | ** ** | ** **                 | ** ** | **United** | ** ** | ** ** | ** ** | **Segmented** | ** ** | ** ** | ** ** |
| ** **                          | ** ** | **Australia**              | ** ** | **States** | ** ** | **Total**  | ** ** | **Items** | ** ** | **Total** | ** ** |
|                                |       |                       |       |       |       |       |       |   |   |   |   |
| Revenues                            |       | $                          | 1,560      |       | $          | 2          |       | $ | 1,562 |   | $ | — |   | $ | 1,562 |   |
| Income  (loss) before income taxes  |       | 188                        |       | (224       | )          | (36        | )          | (3,558 | )(1) | (3,594 | ) |
| Property,  plant and equipment, net |       | 108,036                    |       | 8,466      |       | 116,502    |       | 401 |   | 116,903 |   |
|                                     |            |                            |            |            |            |            |            |  |  |  |  |  |  |  |  |  |

 

----

(1)    Includes $1.5 million ofgeneral and administrative expenses, and $2.1 million of interest expense.

 

**As of andfor the three months ended June 30, 2003**

 
| ** **                          | ** ** | **Gas and Oil Operations** | ** ** | **Non-**   | ** ** | ** ** | ** ** |
|-------------------------------------|------------|----------------------------|------------|------------|------------|------------|------------|
| ** **                          | ** ** | ** **                 | ** ** | **United** | ** ** | ** ** | ** ** | **Segmented** | ** ** | ** ** | ** ** |
| ** **                          | ** ** | **Australia**              | ** ** | **States** | ** ** | **Total**  | ** ** | **Items** | ** ** | **Total** | ** ** |
| Revenues                            |       | $                          | 1,705      |       | $          | 4          |       | $ | 1,709 |   | $ | — |   | $ | 1,709 |   |
| Income  (loss) before income taxes  |       | 428                        |       | (2,443     | )          | (2,015     | )          | 654 | (1) | (1,361 | ) |
| Property,  plant and equipment, net |       | 81,636                     |       | 8,443      |       | 90,079     |       | 387 |   | 90,466 |   |
|                                     |            |                            |            |            |            |            |            |  |  |  |  |  |  |  |  |  |

 

----

(1)    Includes $1.3 million ofgeneral and administrative expenses, $1.2 million of interest expense and $3.1million of foreign currency exchange gain.

 

**As of and for the six monthsended June 30, 2004**

 
| ** **                          | ** ** | **Gas and Oil Operations** | ** ** | **Non-**   | ** ** | ** ** | ** ** |
|-------------------------------------|------------|----------------------------|------------|------------|------------|------------|------------|
| ** **                          | ** ** | ** **                 | ** ** | **United** | ** ** | ** ** | ** ** | **Segmented** | ** ** | ** ** | ** ** |
| ** **                          | ** ** | **Australia**              | ** ** | **States** | ** ** | **Total**  | ** ** | **Items** | ** ** | **Total** | ** ** |
| Revenues                            |       | $                          | 2,726      |       | $          | 4          |       | $ | 2,730 |   | $ | — |   | $ | 2,730 |   |
| Loss  before income taxes           |       | (28                        | )          | (630       | )          | (658       | )          | (7,717 | )(1) | (8,375 | ) |
| Property,  plant and equipment, net |       | 108,036                    |       | 8,466      |       | 116,502    |       | 401 |   | 116,903 |   |
|                                     |            |                            |            |            |            |            |            |  |  |  |  |  |  |  |  |  |

 

----

(1)    Includes $3.5 million ofgeneral and administrative expenses and $4.2 million of interest expense.

 

11

----

 

**As of andfor the six months ended June 30, 2003**

 
| ** **                          | ** ** | **Gas and Oil Operations** | ** ** | **Non-**   | ** ** | ** ** | ** ** |
|-------------------------------------|------------|----------------------------|------------|------------|------------|------------|------------|
| ** **                          | ** ** | ** **                 | ** ** | **United** | ** ** | ** ** | ** ** | **Segmented** | ** ** | ** ** |
| ** **                          | ** ** | **Australia**              | ** ** | **States** | ** ** | **Total**  | ** ** | **Items** | ** ** | **Total** |
|                                |       |                       |       |       |       |       |       |   |   |   |   |
| Revenues                            |       | $                          | 3,043      |       | $          | 7          |       | $ | 3,050 |   | $ | — |   | $ | 3,050 |   |
| Income  (loss) before income taxes  |       | 673                        |       | (2,606     | )          | (1,933     | )          | (2,181 | )(1) | (4,114 | ) |
| Property,  plant and equipment, net |       | 81,636                     |       | 8,443      |       | 90,079     |       | 387 |   | 90,466 |   |
|                                     |            |                            |            |            |            |            |            |  |  |  |  |  |  |  |  |  |

 

----

(1)    Includes $2.8 million ofgeneral and administrative expenses, $2.5 million of interest expense and $3.1million of foreign currency exchange gain.

 

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

 

A summary ofproperty, plant and equipment follows:

 
| ** **                                                 | ** ** | **June 30,  2004** | ** ** | **December 31,  2003** | ** ** |
|------------------------------------------------------------|------------|-------------------------|------------|-----------------------------|------------|
| ** **                                                 | ** ** | **(in thousands)**      | ** ** | ** **                  | ** ** |
|                                                       |       |                    |       |                        |       |
| Evaluated  oil and gas properties:                         |       |                    |       |                        |       |
| Australian  properties                                     |       | $                       | 101,414    |                        | $          | 105,264 |   |
| Domestic  properties                                       |       | —                  |       | —                      |       |
| Unevaluated  oil and gas properties:                       |       |                    |       |                        |       |
| Australian  properties                                     |       | 10,840                  |       | 9,221                       |       |
| Domestic  properties                                       |       | 8,466                   |       | 6,218                       |       |
|                                                       |       |                    |       |                        |       |
| Oil  and gas properties                                    |       | 120,720                 |       | 120,703                     |       |
| Other  property and equipment                              |       | 4,353                   |       | 4,431                       |       |
|                                                       |       | 125,073                 |       | 125,134                     |       |
| Less  accumulated depreciation, depletion and amortization |       | (8,170                  | )          | (8,078                      | )          |
| Property,  plant and equipment, net                        |       | $                       | 116,903    |                        | $          | 117,056 |   |

 

**NOTE 8 –STATEMENT OF CASH FLOWS SUPPLEMENTAL INFORMATION**

 
| ** **                                | ** ** | **Six Months Ended  June 30,** | ** ** |
|-------------------------------------------|------------|-------------------------------------|------------|
| ** **                                | ** ** | **2004**                            | ** ** | **2003** | ** ** |
| ** **                                | ** ** | **(in thousands)**                  | ** ** |
|                                      |       |                                |       |   |   |
| Cash  paid during the period for interest |       | $                                   | 4,779      |   | $ | 1,599 |   |
|                                           |            |                                     |            |  |  |  |  |

 

 

12

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**Item 2****.****           Management’s Discussionand 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.  Words such as “may,” “will,” “expect,” “anticipate,”“estimate” or “continue,” or comparable words are intended to identify suchforward-looking statements. In addition, all statements other than statementsof historical facts that address activities that the Company expects oranticipates will or may occur in the future are forward-lookingstatements.  These statements are notguarantees of future performance and involve certain risks, uncertainties andassumptions that are difficult to predict with regard to timing, extent,likelihood and degree of occurrence. Therefore, actual results and outcomes may materially differ from whatmay be expressed or forecasted in such forward-looking statements. Furthermore,the Company undertakes no obligation to update, amend or clarifyforward-looking statements, whether as a result of new information, futureevents or otherwise. Readers are encouraged to read the SEC filings of theCompany, particularly its Form 10-K for the year ended December 31, 2003,for meaningful cautionary language and discussion of risk factors disclosingwhy actual results may vary materially from those anticipated by management.

 

***Overview***

 

*Australia*

 

The Company’s activitiesin Australia are conducted substantially through Tipperary Corporation’s90%-owned Australian subsidiary, Tipperary Oil & Gas (Australia) Pty Ltd (“TOGA”).  As of June 30, 2004, the Company owned a73% undivided capital bearing interest in the Comet Ridge project inQueensland, Australia.  This projectcomprises approximately 1,230,500 acres in the Bowen Basin, which includes fivepetroleum leases covering approximately 288,000 acres, Authority to Prospect (“ATP”)526 covering approximately 712,000 acres, ATP 653 covering approximately 96,000acres and ATP 745 covering approximately 135,000 acres.  Nearby the Comet Ridge project, the Companyholds a 100% interest in approximately 77,000 acres comprising ATP 655.

 

An ATP allows the holderto undertake 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, Mines and Energy (“Queensland DNRME”) and is subject to renewalevery four years. Once a petroleum resource is identified, the holder of an ATPmay apply for a petroleum lease, which provides the lessee with the ability toconduct additional exploration, development and production activities.

 

The Company is incorrespondence with the Queensland DNRME about surface access issues onportions of ATP 526 and as a consequence is not certain of its 2004 workcommitment for ATP 526.  The ATP 526expenditure requirements net to the Company’s interest will be $3 million orless for a drilling program and $2 million or less for a seismic program.  The ATP 653 expenditure requirements net tothe Company’s interest will be $3 million or less for a drilling program.  During 2004, ATPs 655 and 745 haveexpenditure requirements totaling approximately $1.4 million net to the Company’sinterest.  The Company expects to meetthese requirements by conducting seismic operations and exploratorydrilling.  The 2004 expenditurerequirements for ATPs 526, 655 and 745 must be met by October 31 and forATP 653 by September 30.  ATPs 526,653, 655 and 745 have initial terms expiring on October 31, 2004,September 30, 2006, October 31, 2007 and October 31, 2007,respectively.  Upon expiration of an ATP,the stated policy of the Queensland DNRME allows the ATP holder to renew theATP for an additional four year exploratory period and generally requires theholder to relinquish a 20 percent portion of ATP acreage not held by apetroleum lease.  The Company isnegotiating with the Queensland DNRME regarding petroleum leases that can beestablished on acreage that is part of ATP 526 and ATP 653.  The Company is preparing to negotiate withthe Queensland DNRME regarding the amount of ATP 526 acreage that will besubject to the relinquishment provisions as its term expires October 31,2004.

 

13

----

 

The Company’s gasmarketing in eastern Australia is currently focused on obtaining long-term gassales agreements that provide five to 15 years of firm sales typically startingin 2006 to 2008.  Short-term sales contractsfor 2004 and 2005 are also being pursued. Two short-term sales contracts have been recently signed, one for sixmonths and one for 12 months. These contracts are expected to increase gassales quantities in the near term as the Company prepares to escalate sales to17 Bcf net or more per annum in 2008. The Company anticipates spending approximately $30 million over the nextthree years on development drilling and expansion of delivery facilities toincrease the Company’s annual deliverability to approximately 24 Bcf net by2008.

 

The followingtable summarizes field development progress on the Comet Ridge project as ofJune 30, 2004.  InDecember 2003, the Company began using its second compression plantfacility, which increased the field’s gas compression capacity to approximately38 million cubic feet (“MMcf”) per day.

 

**CometRidge Operations Review**

 

| ** **                         | ** ** | **June 30,  2004** | ** ** |
|------------------------------------|------------|-------------------------|------------|
|                               |       |                    |       |
| **Well Status (Number of Wells)**  |       |                    |       |
| Selling                            |       | 46                      |       |
| Dewatering  or temporarily shut-in |       | 32                      |       |
| Producing                          |       | 78                      |       |
| Being  evaluated                   |       | 21                      |       |
| To  be plugged and abandoned       |       | 2                       |       |
| Plugged  and abandoned             |       | 3                       |       |
|                               |       |                    |       |
| Total  drilled                     |       | 104                     |       |
|                               |       |                    |       |
| **Gross Daily Volumes (MMcf)**     |       |                    |       |
| Sold                               |       | 16                      |       |
| Flared                             |       | 2                       |       |
| Used  for compression fuel         |       | 2                       |       |
|                               |       |                    |       |
| Produced                           |       | 20                      |       |

 

The Company drilled twoexploratory wells on the Comet Ridge project during the first half of2004.  The 2004 drilling wassubstantially funded with borrowings from Slough Trading Estates Limited (“STEL”).  Future 2004 development and exploratory costswill be funded by a $150.0 million AUD senior credit facility described in Note3 to the Consolidated Financial Statements.

 

During the first half of2004, 100% of the Company’s gas sales in Australia were under a five-yearcontract effective June 1, 2000 with ENERGEX Retail Pty Ltd (“ENERGEX”),an unaffiliated customer.  The ENERGEXcontract has delivery requirements of up to approximately 15,000 Mcf of gas perday.  In December 2002, the Companysigned a gas supply term sheet with Origin Energy Retail Limited (“OERL”), asubsidiary of Origin Energy Limited, to supply approximately 9 Bcf per year, orapproximately 25,000 Mcf of gas per day net to the Company’s interests, for 13years beginning May 2007.  Origin Energy Limited is a large Australianintegrated energy company which, through subsidiaries, owns nearly 24% of theComet Ridge project.

 

July’s average grossdaily sales volumes increased to 24,700 Mcf, a 40% increase over June’s salesof 17,700 Mcf due to a new six month contract with ENERGEX and a twelve monthcontract with a new customer.

 

Effective March 31,2004, the Company and Queensland Fertilizer Assets Limited (“QFAL”) extendeduntil September 30, 2004 the Company’s gas sales agreement with QFAL tosupply 210 Bcf of gas to QFAL over a 20-year period beginning in early 2007 toa fertilizer plant QFAL is proposing to construct in southeastern Queensland.

 

14

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***UnitedStates***

 

*Lay Creek*— The Company holds a 50% working interest in Lay Creek, a coalseam gas projectlocated in Moffat County, Colorado. The project includes various leaseholdinterests covering over 82,000 gross acres. Koch Exploration Company (“Koch”),an unaffiliated third party, holds the remaining 50% working interest andoperates the project.  The Company iscurrently evaluating the gas and water production from two pilot areas drilledin 2001 and 2002 in order to determine economic viability of theproduction.  The Company and Koch drilledfour additional pilot wells expanding one of the pilot areas during the periodfrom December 2003 through February 2004 at a cost to the Company of$1.0 million.  The Company is currentlyproducing gas and water from eight wells on the Lay Creek project.  Gas production on the project isapproximately 300 Mcf per day.  TheCompany expects to begin selling Lay Creek gas near the end of 2004.

 

*Frenchman*— The Company holds a 25% interest in the Frenchman prospect in easternColorado.  Total gross acreage in theprospect is approximately 162,000 acres. Kerr-McGee Rocky Mountain Corporation (“Kerr-McGee”) holds the remaining75% interest and is the operator of the prospect.  During 2003, five wells were drilled on theFrenchman prospect.  Three of these wellswere completed and two were plugged and abandoned.  In early 2004, the Company drilled twoadditional Frenchman wells in which Kerr-McGee elected not to participate andresulted in the Company having a 100% interest in these wells.  The Company believes one of these 100% wellswill be a commercial producer and the Company will earn 100% of offsettingdrill sites as set forth in the operating agreement the Company has withKerr-McGee.  The Company plugged andabandoned the other well drilled.  In thefirst quarter of 2004, the Company recorded an asset impairment expense of$150,000 related to unsuccessful exploration costs incurred on wells on theFrenchman prospect.  Two additional 100%wells are planned to be drilled in the third quarter of 2004 at a cost to theCompany of approximately $420,000.  Inaddition, two wells are expected to be drilled jointly by the Company andKerr-McGee in 2004 at a cost to the Company of approximately $157,500.  The economics of connecting the successfullycompleted wells to nearby pipelines are currently being evaluated.

 

*Republican*— The Company holds a 20% interest in the Republican prospect in easternColorado.  Total gross acreage in theprospect is approximately 170,000 acres. Kerr-McGee holds the remaining 80% interest and is the operator of theprospect.  Three wells were drilled onthe Republican prospect in March and April of 2004, and the economicsof connecting these wells to nearby pipelines are being evaluated.  At least seven wells on the Republicanprospect are expected to be drilled in 2004 at a cost to the Company ofapproximately $294,000.

 

*Stateline*— The Company holds a 25% interest in the Stateline prospect in westernNebraska.  Total gross acreage in theprospect is approximately 120,000 acres. Lance Oil & Gas Company, Inc. (“Lance”) holds the remaining 75%interest and is the operator of the prospect. In the first half of 2004, preliminary seismic operations were conductedat a cost to the Company of approximately $100,000.  Further seismic operations and exploratorydrilling may be conducted if the results of the current seismic survey areencouraging.

 

*Sand Hill*— During late 2003, the Company acquired leasehold acreage in western Nebraskatotaling approximately 51,000 gross acres, which is referred to as the SandHill prospect.  This acreage is locatedin the vicinity of the Company’s Frenchman, Republican and Statelineprospects.  The Company is activelymarketing the Sand Hill prospect and plans to sell an interest to recover itsinvestment and retain an interest in this acreage.

 

*Nine Mile* — TheCompany holds a 70% interest in the prospective acreage and 40% interest in theoutlying acreage of the Nine Mile prospect, a conventional oil and gasexploration prospect, also located in Moffat County, Colorado, and serves asoperator of the prospect.  The prospectcomprises approximately 38,000 gross acres. The Company is currently evaluating exploratory work performed in 2002and 2003 and is seeking industry partners before resuming exploratory activity.

 

***FinancialCondition, Liquidity and Capital Resources***

 

The Company had cash andcash equivalents of $1.6 million as of June 30, 2004, compared toapproximately $3.0 million as of December 31, 2003.  The Company has funded operations, deferredloan costs associated with obtaining TOGA’s senior credit facility and capitalexpenditures for the six months ended June 30, 2004, using primarily (a)cash on hand at December 31, 2003 and (b) borrowings from STEL and TOGA’ssenior credit facility.

 

15

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The Company anticipatesfunding operations and capital expenditures in Australia for the remainder of2004 using funds from a $150 million AUD (approximately $114 million USD)financing facility).  See Note 3 to theConsolidated Financial Statements.

 

The Company anticipatesfunding operations and capital expenditures in the United States for 2004 using(a) cash on hand at June 30, 2004 and (b) a commitment from Slough toprovide funds for working capital, board-approved capital expenditures andoperations through April 2005.

 

In order to funddiscretionary capital expenditures in 2004 in excess of these cash resources,the Company contemplates that it will require alternative sources ofcapital.  Potential additional sources offunding may include additional debt financings and asset sales.  With the sale of interests in its prospectiveacreage, the Company expects to generate cash to reduce its investment inindividual projects.  However, in theevent that sufficient funding cannot be obtained, the Company will be requiredto curtail planned expenditures and may have to sell additional acreage and/orrelinquish acreage.

 

Net cash used byoperating activities was $7.1 million during the six months ended June 30,2004, compared to $3.1 million of cash used during the same period lastyear.  The increase in net cash used foroperations in the first half of 2004 compared with the same period in 2003resulted primarily from (a) lower gas revenues (b) higher interest expense ondebt used to fund property acquisition, exploration and development and (c)higher operating costs and general and administrative expenses.

 

On June 9, 2004,TOGA entered into a $150.0 million AUD senior credit facility agreement withAustralia and New Zealand Banking Group Limited and BOS International(Australia) Limited.  The initialborrowings under the facility totaled $103.0 million AUD ($71.0 millionUS).  TOGA used $100.0 million AUD ($68.2million US) to pay in full its borrowings from STEL and to pay debt issuancecosts.  The balance of the creditfacility will be used to fund TOGA’s share of development costs of the CometRidge coalseam gas project in Queensland, Australia.

 

The table below providesan analysis of capital expenditures of $9.4 million during the six months endedJune 30, 2004.

 

**Capital Expenditures Activity**

**(in thousands)**

 
| Australia:                            |   |   |   |
|---------------------------------------|--------|--------|--------|
| Comet  Ridge drilling and completion  |   | $      | 6,018  |   |
| Comet  Ridge facilities and equipment |   | 171    |   |
| Other                                 |   | 850    |   |
| Domestic:                             |   |   |   |
| Leasehold  acquisitions               |   | 1,023  |   |
| Lay  Creek drilling and completion    |   | 981    |   |
| Other  drilling and completion        |   | 388    |   |
|                                  |   |   |   |
| Total                                 |   | $      | 9,431  |   |

 

Included within the firstsix months of 2004 capital spending was $873,000 of capitalized interestexpense associated with the Company’s Australian and domestic properties.  Capital expenditures for the first six monthsof 2004 were funded principally under TOGA’s credit facilities with STEL.

 

16

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***Resultsof Operations - Comparison of the Three Months Ended June 30, 2004 and2003***

 

The Company incurred anet loss of $3.5 million for the three months ended June 30, 2004 comparedto a net loss of $1.6 million for the three months ended June 30,2003.  The greater net loss for the threemonths ended June 30, 2004 was primarily due to interest expense onadditional debt used to fund property exploration and development.  Additionally, during the three months endedJune 30, 2003, the Company recorded a $3.1 million foreign currencyexchange gain offset by a $2.2 million impairment of oil and gas properties.  The table below provides a comparison ofoperations for the three months ended June 30, 2004 with those of theprior year’s second quarter.  The tableis intended to provide a comparative review of significant operationalitems.  Accordingly, nominal differencesmay exist from the amounts presented in the accompanying Consolidated FinancialStatements.

 
| ** **                                                       | ** ** | **Three Months Ended  June 30,**                              | ** ** | **Increase  (Decrease)** | ** ** | **%****Increase  (Decrease)** | ** ** |
|------------------------------------------------------------------|------------|--------------------------------------------------------------------|------------|--------------------------|------------|-------------------------------|------------|
| ** **                                                       | ** ** | **2004**                                                           | ** ** | **2003**                 | ** ** |
| ** **                                                       | ** ** | **($ in thousands, except average per Mcf prices and costs)** | ** ** |
| **Worldwide operations:**                                        | ** ** | ** **                                                         | ** ** | ** **               | ** ** | ** **                    | ** ** | ** ** | ** ** |
|                                                             |       |                                                               |       |                     |       |                          |       |   |   |
| Operating  revenue                                               |       | $                                                                  | 1,562      |                     | $          | 1,709                         |       | $ | (147 | ) | (9 | )% |
| Gas  volumes (MMcf)                                              |       | 938                                                                |       | 1,171                    |       | (233                          | )          | (20 | )% |
| Average  gas price per Mcf                                       |       | $                                                                  | 1.66       |                     | $          | 1.46                          |       | $ | 0.20 |   | 14 | % |
| Operating  expenses                                              |       | $                                                                  | 1,247      |                     | $          | 1,111                         |       | $ | 136 |   | 12 | % |
| Average lifting cost per Mcf equivalent (“Mcfe”)  sold |       | $                                                                  | 1.33       |                     | $          | 0.95                          |       | $ | 0.38 |   | 40 | % |
| General  and administrative                                      |       | $                                                                  | 1,510      |                     | $          | 1,291                         |       | $ | 219 |   | 17 | % |
| Depreciation,  depletion and amortization (“DD&A”) |       | $                                                                  | 356        |                     | $          | 398                           |       | $ | (42 | ) | (11 | )% |
| Impairment  of oil and gas properties                            |       | $                                                                  | —     |                     | $          | 2,221                         |       | $ | (2,221 | ) | N/A |   |
| Interest  expense                                                |       | $                                                                  | 2,097      |                     | $          | 1,175                         |       | $ | 922 |   | 78 | % |
|                                                             |       |                                                               |       |                     |       |                          |       |   |   |
| **Australia operations:**                                        |       |                                                               |       |                     |       |                          |       |   |   |
|                                                             |       |                                                               |       |                     |       |                          |       |   |   |
| Operating  revenue                                               |       | $                                                                  | 1,560      |                     | $          | 1,705                         |       | $ | (145 | ) | (9 | )% |
| Gas  volumes (MMcf)                                              |       | 938                                                                |       | 1,170                    |       | (232                          | )          | (20 | )% |
| Average  gas price per Mcf                                       |       | $                                                                  | 1.66       |                     | $          | 1.46                          |       | $ | 0.20 |   | 14 | % |
| Operating  expenses                                              |       | $                                                                  | 1,025      |                     | $          | 888                           |       | $ | 137 |   | 15 | % |
| Average  lifting cost per Mcf sold                               |       | $                                                                  | 1.09       |                     | $          | 0.76                          |       | $ | 0.33 |   | 43 | % |
| Oil  and Gas property DD&A                                   |       | $                                                                  | 308        |                     | $          | 372                           |       | $ | (64 | ) | (17 | )% |
| Other  DD&A                                                  |       | $                                                                  | 34         |                     | $          | 14                            |       | $ | 20 |   | 143 | % |
| Oil  and Gas DD&A rate per Mcf volumes sold             |       | $                                                                  | 0.33       |                     | $          | 0.32                          |       | $ | 0.01 |   | 3 | % |
|                                                             |       |                                                               |       |                     |       |                          |       |   |   |
| **Domestic operations:**                                         |       |                                                               |       |                     |       |                          |       |   |   |
|                                                             |       |                                                               |       |                     |       |                          |       |   |   |
| Operating  revenue                                               |       | $                                                                  | 2          |                     | $          | 4                             |       | $ | (2 | ) | (50 | )% |
| Gas  volumes (MMcf)                                              |       | 0.5                                                                |       | 1                        |       | (.5                           | )          | (50 | )% |
| Average  gas price per Mcf                                       |       | $                                                                  | 4.08       |                     | $          | 4.00                          |       | $ | 0.08 |   | 2 | % |
| Operating  expenses – producing properties                  |       | $                                                                  | 1          |                     | $          | 2                             |       | $ | 1 |   | 50 | % |
| Average  lifting cost on producing properties per Mcfe sold      |       | $                                                                  | 2.31       |                     | $          | 1.98                          |       | $ | 0.33 |   | 17 | % |
| Operating  expenses – non-producing properties              |       | $                                                                  | 221        |                     | $          | 221                           |       | $ | — |   | — |   |
| Other  DD&A                                                  |       | $                                                                  | 14         |                     | $          | 12                            |       | $ | 2 |   | 17 | % |

 

17

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Revenues and SalesVolumes

 

The Company is currentlyselling its Australian gas under a five-year contract with deliveryrequirements of up to 15,000 Mcf of gas per day to Energex, an unaffiliatedcustomer.  In 2003, the Company had twoEnergex contracts, one of which expired at the end of 2003, with combineddelivery requirements of up to 20,300 Mcf of gas per day.  The reduction in gas delivery requirements of5,300 Mcf per day was the principal cause for the 20% decline in gas volumessold in Australia in the second quarter of 2004 compared with the same periodin 2003.  The Company is actively pursuinglong-term and short-term gas contracts to increase gas volumes sold.  Effective July 2004, the Company enteredinto two short-term contracts:  one forsix months with ENERGEX and one for twelve months with a new customer.  With the addition of these two contracts,July’s average gross daily sales volumes increased to 24,700 Mcf, a 40%increase over June’s sales of 17,700 Mcf. Gas revenues in Australia for the second quarter decreased by 9% due tothe lower sales volumes, offset by an increase in the average sales pricereceived and changes in exchange rates. The 14% increase in average gas sales price in Australia is dueprimarily to favorable changes in exchange rates.

 

During the second quarterof 2004, the Company had minimal domestic revenue.  Domestic revenues and volumes in 2004 and2003 relate to small, retained interests in properties producing in the PowderRiver Basin in Wyoming.

 

Costs and Expenses

 

Operating expenses inAustralia increased 15% due to the addition of a second compressor facilitywhich commenced operations in December 2003.  Australian oil and gas property DD&Aexpense decreased 17% due principally to lower sales volumes.

 

Domestic operatingexpenses in the second quarter of 2004 and 2003 are principally attributable tothe Lay Creek coal-seam gas project where the wells are in the dewateringphase.

 

General andadministrative (“G&A”) expenses for the second quarter of 2004 increased16% compared to the three months ended June 30, 2003.  This increase is attributed to higheremployee and consulting costs associated with managing the Comet Ridgeproperties and continuing costs for the Tri-Star litigation.

 

Other Income (Expense)

 

Interest expenseincreased to $2.1 million from $1.2 million, due primarily to increased loanbalances in the second quarter of 2004 as compared to the same period in 2003.

 

18

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***Resultsof Operations - Comparison of the Six Months Ended June 30, 2004 and 2003***

 

The Company incurred anet loss of $8.0 million for the six months ended June 30, 2004 comparedto a net loss of $4.3 million for the six months ended June 30, 2003.  The greater net loss for the six months endedJune 30, 2004 was primarily due to (i) interest expense on additional debtused to fund property exploration and development, (ii) increased operatingcosts and (iii) increased general and administrative expenses.  Additionally, during the six months endedJune 30, 2003, the Company recorded a $3.1 million foreign currency gainoffset by a $2.2 million impairment of oil and gas properties.  The table below provides a comparison ofoperations for the six months ended June 30, 2004 with those of the prioryear’s six-month period.  The table isintended to provide a comparative review of significant operational items.Accordingly, nominal differences may exist from the amounts presented in theaccompanying Consolidated Financial Statements.

 
| ** **                                                       | ** ** | **Six Months Ended  June 30,**                                | ** ** | **Increase  (Decrease)** | ** ** | **%****Increase  (Decrease)** | ** ** |
|------------------------------------------------------------------|------------|--------------------------------------------------------------------|------------|--------------------------|------------|-------------------------------|------------|
| ** **                                                       | ** ** | **2004**                                                           | ** ** | **2003**                 | ** ** | ** **                    | ** ** |
| ** **                                                       | ** ** | **($ in thousands, except average per Mcf prices and costs)** | ** ** |
| **Worldwide operations:**                                        |       |                                                               |       |                     |       |                          |       |   |   |
|                                                             |       |                                                               |       |                     |       |                          |       |   |   |
| Operating  revenue                                               |       | $                                                                  | 2,730      |                     | $          | 3,050                         |       | $ | (320 | ) | (10 | )% |
| Gas  volumes (MMcf)                                              |       | 1,589                                                              |       | 2,183                    |       | (594                          | )          | (27 | )% |
| Average  gas price per Mcf                                       |       | $                                                                  | 1.72       |                     | $          | 1.40                          |       | $ | 0.32 |   | 23 | % |
| Operating  expenses                                              |       | $                                                                  | 2,641      |                     | $          | 2,068                         |       | $ | 573 |   | 28 | % |
| Average lifting cost per Mcf equivalent (“Mcfe”)  sold |       | $                                                                  | 1.66       |                     | $          | 0.95                          |       | $ | .71 |   | 75 | % |
| General  and administrative                                      |       | $                                                                  | 3,554      |                     | $          | 2,812                         |       | $ | 742 |   | 26 | % |
| Depreciation,  depletion and amortization (“DD&A”) |       | $                                                                  | 607        |                     | $          | 706                           |       | $ | (99 | ) | (14 | )% |
| Impairment  of oil and gas properties                            |       | $                                                                  | 150        |                     | $          | 2,221                         |       | $ | (2,071 | ) | (93 | )% |
| Interest  expense                                                |       | $                                                                  | 4,233      |                     | $          | 2,480                         |       | $ | 1,753 |   | 71 | % |
|                                                             |       |                                                               |       |                     |       |                          |       |   |   |
| **Australia operations:**                                        |       |                                                               |       |                     |       |                          |       |   |   |
|                                                             |       |                                                               |       |                     |       |                          |       |   |   |
| Operating  revenue                                               |       | $                                                                  | 2,726      |                     | $          | 3,043                         |       | $ | (317 | ) | (10 | )% |
| Gas  volumes (MMcf)                                              |       | 1,588                                                              |       | 2,181                    |       | (593                          | )          | (27 | )% |
| Average  gas price per Mcf                                       |       | $                                                                  | 1.72       |                     | $          | 1.40                          |       | $ | 0.32 |   | 23 | % |
| Operating  expenses                                              |       | $                                                                  | 2,165      |                     | $          | 1,682                         |       | $ | 483 |   | 29 | % |
| Average  lifting cost per Mcf sold                               |       | $                                                                  | 1.36       |                     | $          | 0.77                          |       | $ | 0.59 |   | 77 | % |
| Oil  and Gas property DD&A                                   |       | $                                                                  | 510        |                     | $          | 654                           |       | $ | (144 | ) | (22 | )% |
| Other  DD&A                                                  |       | $                                                                  | 69         |                     | $          | 28                            |       | $ | 41 |   | 146 | % |
| Oil  and Gas DD&A rate per Mcf volumes sold             |       | $                                                                  | 0.32       |                     | $          | 0.29                          |       | $ | 0.03 |   | 10 | % |
|                                                             |       |                                                               |       |                     |       |                          |       |   |   |
| **Domestic operations:**                                         |       |                                                               |       |                     |       |                          |       |   |   |
|                                                             |       |                                                               |       |                     |       |                          |       |   |   |
| Operating  revenue                                               |       | $                                                                  | 4          |                     | $          | 7                             |       | $ | (3 | ) | (43 | )% |
| Gas  volumes (MMcf)                                              |       | 1                                                                  |       | 1                        |       | —                        |       | — |   |
| Average  gas price per Mcf                                       |       | $                                                                  | 4.04       |                     | $          | 3.95                          |       | $ | 0.09 |   | 2 | % |
| Operating  expenses – producing properties                  |       | $                                                                  | 2          |                     | $          | 3                             |       | $ | (1 | ) | (33 | )% |
| Average  lifting cost on producing properties per Mcfe sold      |       | $                                                                  | 2.29       |                     | $          | 2.05                          |       | $ | 0.24 |   | 12 | % |
| Operating  expenses – non-producing properties              |       | $                                                                  | 474        |                     | $          | 383                           |       | $ | 91 |   | 24 | % |
| Impairment  of oil and gas properties                            |       | $                                                                  | 150        |                     | $          | 2,221                         |       | $ | (2,071 | ) | (93 | )% |
| Other  DD&A                                                  |       | $                                                                  | 28         |                     | $          | 25                            |       | $ | 3 |   | 12 | % |

 

19

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Revenues and SalesVolumes

 

The Company is currentlyselling its Australian gas under a five-year contract with deliveryrequirements of up to 15,000 Mcf of gas per day to Energex, an unaffiliatedcustomer.  In 2003, the Company had twoEnergex contracts, one of which expired at the end of 2003, with combineddelivery requirements of up to 20,300 Mcf of gas per day.  The reduction in gas delivery requirements of5,300 Mcf per day was the principal cause for the 27% decline in gas volumessold in Australia in the first half of 2004 compared with the same period in2003.  The Company is actively pursuinglong-term and short-term gas contracts to increase gas volumes sold.  Effective July 2004, the Company entered intotwo short-term contracts: one for six months with ENERGEX and one for twelvemonths with a new customer. With the addition of these two contracts, July’saverage gross daily sales volumes increased to 24,700 Mcf, a 40% increase overJune’s sales of 17,700 Mcf.  Gas revenuesin Australia decreased by 10% due to the lower sales volumes, offset by anincrease in the average sales price received and changes in exchangerates.  The 23% increase in average gassales price in Australia is due primarily to favorable changes in exchangerates.

 

During the first half of2004, the Company had minimal domestic revenue. Domestic revenues and volumes in 2004 and 2003 relate to small, retainedinterests in properties producing in the Powder River Basin in Wyoming.

 

Costs and Expenses

 

Operating expenses inAustralia increased 29% due to an increase in the number of producing wells andthe addition of a second compressor facility which commenced operations inDecember 2003.  Australian oil andgas property DD&A expense decreased 22% due principally to lower salesvolumes.

 

Domestic operatingexpenses in the first half of 2004 and 2003 were principally attributable tothe Lay Creek coal-seam gas project where the wells are in the dewateringphase.

 

The impairment expense of$150,000 was attributed to unsuccessful exploration costs incurred on wells onthe Frenchman prospect.

 

General andadministrative (“G&A”) expenses for the first half of 2004 increased 26%compared to the six months ended June 30, 2003.  This increase was due to higher employee andconsulting costs associated with managing the Comet Ridge properties andcontinuing costs for the Tri-Star litigation.

 

Other Income (Expense)

 

Interest expenseincreased to $4.2 million from $2.5 million, due primarily to increased loanbalances in the first half of 2004 as compared to the same period in 2003.

 

 

***CriticalAccounting Policies***

 

The Company’s financialstatements are based on the selection and application of significant accountingpolicies, some of which require management to make estimates and assumptionswhich affect the reported amounts of assets, liabilities, revenues and expensesand also affect the disclosure of contingent items.  A summary of the Company’s significantaccounting policies is included in Item 7 of the Company’s annual report onForm 10-K for the year ended December 31, 2003.  The Company believes that the significantaccounting policies discussed therein are some of the more critical judgmentareas in application of its accounting policies that currently affect itsfinancial condition and results of operations.

 

20

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**Item 3****.****           Quantitative andQualitative Disclosure About Market Risk**

 

Market risk is thepotential loss arising from adverse changes in market rates and prices, such asforeign currency exchange, interest rates and commodity prices.  The Company does not use financialinstruments to any degree to manage foreign currency, interest rate orcommodity risk and does not hold or issue financial instruments to any degreefor trading purposes.  At June 30,2004, the Company was exposed to some market risk with respect to foreigncurrency, long-term debt, and natural gas prices; however, management did notbelieve such risk to be material.  TheCompany’s market risk, discussed in Item 7A in its Annual Report on Form 10-Kfor the year ended December 31, 2003, was unchanged as of June 30,2004.

 

**Item 4****.  Controls and Procedures**

 

As of the end of the period covered by this report, weevaluated, under the supervision and with the participation of our management,including our Chief Executive Officer and Chief Financial Officer, theeffectiveness of the design and operation of our disclosure controls andprocedures over financial reporting pursuant to Rule 13a-15 and 15d-15 of theSecurities Exchange Act of 1934. Based upon that evaluation, our ChiefExecutive Officer and our Chief Financial Officer concluded that our disclosurecontrols and procedures over financial reporting are adequate and effective atthe reasonable assurance level in timely alerting them to material informationrequired to be included in this quarterly report on Form 10-Q.

 

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 indisclosure controls and procedures. These limitations include the fact thathuman judgment in decision-making can be faulty and that breakdowns in internalcontrol can occur because of human failures such as simple errors or mistakesor because of intentional circumvention of the established process.

 

During the period coveredby this report, there have been no changes in our internal controls overfinancial reporting or in other factors, which could significantly affectinternal controls over financial reporting, including any corrective actionswith regard to significant deficiencies or material weaknesses.

 

21

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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 2.             Changes in Securities

 

During the quarterlyperiod ended June 30, 2004, the Company issued 5,000 shares of its commonstock upon the exercise of options with a weighted average exercise price of$2.50 per share.  The issuance of thesesecurities was deemed to be exempt from registration under Section 4(2) ofthe Securities Act of 1933 or Regulation D thereunder as a transaction by an issuernot involving a public offering.

 

Item 4.             Submission of Matters to a Vote ofSecurity Holders

 

The following matterswere voted on at our Annual Meeting of Stockholders held on April 27,2004:

 

The seven members of theBoard of Directors, David L. Bradshaw, Kenneth L. Ancell, Eugene I. Davis,Douglas Kramer, Marshall D. Lees, Charles T. Maxwell and D. Leroy Sample, wereelected as Directors to serve until the next Annual Meeting of Shareholders oruntil their successors have been elected and qualified.

 

The reappointment ofPricewaterhouseCoopers LLP as the Company’s auditors for 2004 was ratified.

 

Item 6.             Exhibits and Reportson Form 8-K

 

(a)                                  Exhibits:

 

Filed in Part I

 

31.1                           Certificationof Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of2002.

 

31.2                           Certificationof Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of2002.

 

32.1                           Certificationof Chief Executive Officer of Tipperary Corporation Pursuant to 18 U.S.C.§1350.

 

32.2                           Certificationof Chief Financial Officer of Tipperary Corporation Pursuant to 18 U.S.C.§1350.

 

The other exhibits of theCompany are incorporated herein by reference to the exhibit list in the Company’sAnnual Report on Form 10-K for the year ended December 31, 2003.

 

(b)                                 Reportson Form 8-K:

 

The Registrant submitteda Form 8-K on May 14, 2004, under Item 12 whereby it furnished its earningspress release announcing first quarter 2004 financial results.

 

The Registrant filed aForm 8-K on June 30, 2004, under Items 5 and 7 whereby it furnished itspress release announcing the Facilities Agreement on June 9, 2004 andrelated exhibit.

 

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**SIGNATURES**

 

 

Pursuant to therequirements of the Securities Exchange Act of 1934, the Registrant has dulycaused this report to be signed on its behalf by the undersigned thereunto dulyauthorized.

 

 
|   |                   |   | 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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**EXHIBIT INDEX**

 

 

31.1                           Certificationof Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of2002.

 

 

31.2                           Certificationof Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of2002.

 

 

32.1                           Certificationof Chief Executive Officer of Tipperary Corporation Pursuant to 18 U.S.C.§1350.

 

 

32.2                           Certificationof Chief Financial Officer of Tipperary Corporation Pursuant to 18 U.S.C.§1350.

 

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