UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

 

FORM 10-Q

 

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

 

Commission File Number 1-7796

 

TIPPERARY CORPORATION

(Exact name of registrant as specified in its charter)

 

Texas		75-1236955
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
633 Seventeenth Street, Suite 1550 Denver, Colorado		80202
(Address of principal executive offices)		(Zip Code)

 

(303) 293-9379

(Issuer’s telephone number)

 

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

Yes   ý                No  o

 

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

Yes   o                No  ý

 

State the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

 

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

 

 

TIPPERARY CORPORATION AND SUBSIDIARIES

 

Index to Form 10-Q

 

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

 

---

 

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 to Consolidated Financial Statements.

 

2

 

TIPPERARY CORPORATION AND SUBSIDIARIES

Consolidated Statement of Stockholders’ Equity (Unaudited)

For the Six Months Ended June 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

 

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

 

TIPPERARY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

NOTE 1 – OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES

 

Basis of Presentation

 

In the opinion of management, the accompanying unaudited Consolidated Financial Statements reflect all adjustments, consisting only of normal recurring adjustments, which are necessary for a fair presentation of the financial position of Tipperary Corporation and its subsidiaries (the “Company”) at June 30, 2004, and the results of their operations for the three-month and six-month periods ended June 30, 2004 and 2003 and their cash flows for the six-month periods ended June 30, 2004 and 2003. The Consolidated Financial Statements include the accounts of Tipperary Corporation and its wholly-owned subsidiaries, Tipperary Oil and Gas Corporation, Tipperary CSG Inc. and Burro Pipeline Corporation, and its 90%-owned subsidiary, Tipperary Oil and Gas (Australia) Pty Ltd (“TOGA”).  All intercompany balances have been eliminated.  The accounting policies followed by the Company are included in Note 1 to the Consolidated Financial Statements in its Annual Report on Form 10-K for the year ended December 31, 2003.  These financial statements should be read in conjunction with the Form 10-K.

 

New Accounting Pronouncements

 

The Company has reviewed all recently issued, but not yet adopted, accounting pronouncements and standards to determine their effects, if any, on its results of operations or financial position.  Based on its review, the Company believes that none of these pronouncements will have a significant effect on its current or future financial position or results of operations.

 

Asset Retirement Obligations

 

On January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”), which provides accounting requirements for retirement obligations associated with tangible long-lived assets, including the timing of liability recognition, initial measurement of the liability, allocation of asset retirement costs to expense, subsequent measurement of the liability, and financial statement disclosures.  SFAS No. 143 requires that asset retirement costs be capitalized along with the cost of the related long-lived asset.  The asset retirement costs should then be allocated to expense using a systematic and rational method.  The Company has determined that it has asset retirement costs associated with wells drilled in Australia and the United States. The Company also expects to incur retirement costs to dismantle two gas compression plant facilities located in Australia. The following table sets forth 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 and Goodwill and Intangible Assets

 

In June 2001, the FASB 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 and January 1, 2002, respectively. SFAS No. 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. Additionally, SFAS No. 141 requires companies to disaggregate and report separately from goodwill certain intangible assets.  SFAS No. 142 establishes new guidelines for accounting for goodwill and other intangible assets. Under SFAS No. 142, goodwill and certain other intangible assets are not amortized, but rather are reviewed annually for impairment. One interpretation that was considered relative to these standards was that oil and gas mineral rights held under

 

5

 

lease and other contractual arrangements representing the right to extract such reserves for both undeveloped and developed leaseholds should be classified separately from oil and gas properties, as intangible assets on the Company’s consolidated balance sheets.  In April 2004, the Financial Accounting Standards Board amended SFAS Nos. 141 and 142 and clarified the interpretation by defining mineral rights, such as oil and gas mineral rights, as tangible assets.  Accordingly, the guidelines for accounting for intangible assets as provided in SFAS No. 142 would not apply to oil and gas mineral rights.  In accordance with this new guideline, the Company will continue to classify its contractual rights to extract oil and gas reserves as tangible oil and gas properties.

 

Stock-Based Compensation

 

SFAS Nos. 148 and No. 123 encourage, but do not require, companies to record the compensation cost for stock-based employee compensation plans at fair value.  At June 30, 2004, the Company had two stock-based employee option plans and warrants issued to directors and employees.  The Company has chosen to continue to account for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” (“APB 25”) and has applied the disclosure provisions of SFAS Nos. 123 and 148.  Accordingly, compensation cost for fixed stock options and warrants is measured as the excess, if any, of the quoted market price of the Company’s stock at the date of the grant over the amount an employee must pay to acquire the stock.  Pro forma disclosures as if the Company had adopted the cost recognition provisions of SFAS Nos. 148 and 123 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

 

Revenue Recognition and Gas Imbalances

 

The Company recognizes natural gas and oil revenue from its interests in producing wells as natural gas and oil are produced and sold from those wells. The Company uses the sales method of accounting for these revenues. Under the sales method, revenues are recognized based on actual volumes sold to purchasers. With natural gas production operations, joint owners may take more or less than the production volumes entitled to them under the governing operating agreement. The Company records a natural gas imbalance in other liabilities if its excess takes of natural gas exceed its remaining proved reserves for the property.  As of June 30, 2004, the Company had taken and sold more than its entitled share of natural gas volumes produced from 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 million in gas revenues. No liability has been recorded for the excess volumes taken, as they do not exceed the Company’s share of remaining proved reserves. Under the terms of the governing gas balancing agreement, the Company may be required to reduce the monthly volumes it sells by up to 50% of its entitled share of sales, to enable underproduced parties to sell more than their entitled share of the gas sales and cure the imbalance.

 

Foreign Currency

 

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

 

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

 

Liquidity and Operations

 

The Company anticipates funding operations and capital expenditures in Australia for the remainder of 2004 using funds from a $150 million AUD (approximately $114 million USD) financing facility (see Note 3).

 

The Company anticipates funding 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 Estates USA Inc. (“Slough”), the Company’s majority shareholder, to provide funds for working capital, board-approved capital expenditures and operations through April 2005.

 

In order to fund discretionary domestic capital expenditures in 2004 in excess of these cash resources, the Company contemplates that it will require alternative sources of capital.  Potential additional sources of funding may include additional debt financings and asset sales.  With the sale of interests in its prospective acreage, the Company expects to generate cash to reduce its investment in individual projects.  However, in the event that sufficient funding cannot be obtained, the Company will be required to curtail planned expenditures and may have to sell additional acreage and/or relinquish acreage.

 

NOTE 2 - RELATED PARTY TRANSACTIONS

 

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

 

As of June 30, 2004, the Company had one credit facility agreement with STEL 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 substantially funded its operating and capital needs in the United States during 2003 and through the first half of 2004. The Company may repay the loan in whole or in part without prepayment penalties.  The credit facility bears interest at 13% per annum and is due April 2, 2012.  STEL may demand repayment prior to the maturity date provided that STEL gives 18-

 

7

 

months notice. The Company is limited in taking on any additional third party indebtedness, either secured or unsecured, or making a priority payment in respect of any obligation without first obtaining written approval from STEL so long as the STEL indebtedness exists. In connection with this credit facility, the Company paid STEL arrangement fees of $40,000.  The U.S. dollar values of the outstanding balances of these facilities as of June 30, 2004 were $11.5 million.

 

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

 

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

 

In August 2003, TOGA borrowed $29.7 million ($45 million AUD) from STEL for the sole purpose of paying off a $22 million long-term debt owed TCW Asset Management Company (“TCW”) and to substantially fund a $7.7 million repurchase of the 6% overriding royalty held by TCW on the Company’s Comet Ridge properties.  In addition, TOGA borrowed $55.0 million AUD under a credit facility agreement with STEL to fund its operations in Australia.  These loans bear interest at 13% per annum.  In connection with these loans, the Company paid arrangement fees of $250,000 USD and $100,000 AUD, respectively, to STEL.  These loans were paid in full June 18, 2004 with funds from a bank credit facility (see Note 3).

 

For the six month periods ended June 30, 2004 and 2003, approximately $4.7 million and $656,000, respectively, in interest and fees were paid collectively to Slough and STEL under 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 with Australia 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 of development costs of the Comet Ridge coalseam gas project in Queensland, Australia.  Funds from the facility are expected to be available over five years and repayable in variable portions beginning 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 of committed but undrawn funds, as defined in the credit facility, are payable semi-annually.  The facility is collateralized by, among other things, TOGA’s common stock and the Company’s consolidated interest in the Comet Ridge project and is guaranteed for up to five years by Slough Estates plc (See Note 2).  The facility contains certain restrictive covenants, including maintenance of certain financial ratios.  The U.S. dollar value of the outstanding balance of this facility as of June 30, 2004 was approximately $71.0 million ($103.0 million AUD).  TOGA incurred $4.0 million in loan costs which TOGA has deferred and is amortizing over five years.

 

8

 

NOTE 4 - LOSS PER SHARE

 

The following tables set forth the computation of basic and diluted loss per share (“EPS”) (in thousands except 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 AND CONTINGENCIES

 

The Company, TOGA and two unaffiliated working interest owners are plaintiffs in a lawsuit filed in 1998, styled Tipperary Corporation and Tipperary Oil & Gas (Australia) Pty Ltd v. Tri-Star Petroleum Company, James H. Butler, Sr., and James H. Butler, Jr., Cause No. CV42,265, District Court of Midland County, Texas involving the Comet Ridge project. The plaintiffs allege, among other matters, that Tri-Star and/or the individual defendants failed to operate the project in a good and workmanlike manner and committed various other breaches of a joint operating contract, breached a previous mediation agreement, committed certain breaches of fiduciary and other duties owed to the plaintiffs, and committed fraud in connection with the project.  Tri-Star has 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 to include claims for various breaches of the joint operating contract by the Company and TOGA, other breaches of duties, forfeiture of acreage and unjust enrichment.  Tri-Star has also requested foreclosure of operator’s liens, modification and reformation of the joint operating contract.  TOGA has operated the project since March 2002, after the court entered its Writ of Temporary Injunction (the “Injunction”) to enforce the votes of a majority-in-interest of the parties under the joint operating agreement to remove Tri-Star as operator and replace it with TOGA.  All available appeals of the Injunction have been exhausted and TOGA will continue as operator of the Comet Ridge Project at least through the conclusion of a trial on the merits, and thereafter if it is successful at trial.

 

In June 2002, the District Court ruled as unenforceable the arbitration provisions of the existing mediation agreement between the parties.  With the exception of a Motion for Reconsideration to the Texas Supreme Court which may be filed, all available appeals of the arbitration issues have been exhausted.  The case is set for trial beginning November 2, 2004.

 

On October 1, 2003, the District Court signed an Order finding that Tri-Star willfully disobeyed the Injunction, ordering Tri-Star to cooperate with the Operator and, among other things, to execute a power of attorney to allow the Company to deal directly with the surface owners and governmental authorities on matters pertaining to the Comet Ridge Project. Tri-Star filed objections to the power of attorney. In January 2004, the District Court conducted a show cause hearing to determine whether sanctions for Tri-Star’s past violations of the Injunction, and conditional sanctions to deter future violations, should be imposed and heard a Tri-Star motion to increase the amount of the bond securing the injunction from $500,000 to $1.0 million and objections to the power of attorney.  On March 8, 2004, the District Court ruled that the bond will not be increased and denied Tri-Star’s objections.  The District Court has awarded $283,631 in sanctions against Tri-Star, payable upon final judgment.  Tri-Star unsuccessfully appealed 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 the Texas Supreme Court.  The Company filed response briefs and requested sanctions against Tri-Star.  Hearing the case is discretionary in the Texas Supreme Court, and the Court has made no decision, at this time, on whether to accept review.

 

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

 

10

 

 

NOTE 6 - OPERATIONS BY GEOGRAPHIC AREA

 

Segment information has been prepared in accordance with SFAS No. 131, “Disclosures About Segments of an Enterprise and Related Information.”  The Company has two geographic reporting segments, Australia and the United States, within the oil and gas exploration, development and production industry.  General and administrative expenses, interest expense and interest and other income are not allocated to segments.  The segment data presented below was prepared on the same basis as the Consolidated Financial Statements.  Reportable business segment information as of June 30, 2004 and 2003 and for the three and six months ended June 30, 2004 and 2003 is as follows (in thousands):

 

As of and for the three months ended 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 of general and administrative expenses, and $2.1 million of interest expense.

 

As of and for 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 of general and administrative expenses, $1.2 million of interest expense and $3.1 million of foreign currency exchange gain.

 

As of and for the six months ended 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 of general and administrative expenses and $4.2 million of interest expense.

 

11

 

As of and for 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 of general and administrative expenses, $2.5 million of interest expense and $3.1 million of foreign currency exchange gain.

 

NOTE 7– PROPERTY, PLANT AND EQUIPMENT

 

A summary of property, 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

 

Item 2.           Management’s Discussion and Analysis

 

Information within this report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are based on management’s beliefs, assumptions, current expectations, estimates and projections about the oil and gas industry, the world economy and about the Company itself.  Words such as “may,” “will,” “expect,” “anticipate,” “estimate” or “continue,” or comparable words are intended to identify such forward-looking statements. In addition, all statements other than statements of historical facts that address activities that the Company expects or anticipates will or may occur in the future are forward-looking statements.  These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict with regard to timing, extent, likelihood and degree of occurrence.  Therefore, actual results and outcomes may materially differ from what may be expressed or forecasted in such forward-looking statements. Furthermore, the Company undertakes no obligation to update, amend or clarify forward-looking statements, whether as a result of new information, future events or otherwise. Readers are encouraged to read the SEC filings of the Company, particularly its Form 10-K for the year ended December 31, 2003, for meaningful cautionary language and discussion of risk factors disclosing why actual results may vary materially from those anticipated by management.

 

Overview

 

Australia

 

The Company’s activities in Australia are conducted substantially through Tipperary Corporation’s 90%-owned Australian subsidiary, Tipperary Oil & Gas (Australia) Pty Ltd (“TOGA”).  As of June 30, 2004, the Company owned a 73% undivided capital bearing interest in the Comet Ridge project in Queensland, Australia.  This project comprises approximately 1,230,500 acres in the Bowen Basin, which includes five petroleum leases covering approximately 288,000 acres, Authority to Prospect (“ATP”) 526 covering approximately 712,000 acres, ATP 653 covering approximately 96,000 acres and ATP 745 covering approximately 135,000 acres.  Nearby the Comet Ridge project, the Company holds a 100% interest in approximately 77,000 acres comprising ATP 655.

 

An ATP allows the holder to undertake a range of exploration activities, including geophysical surveys, field mapping and exploratory drilling. Each ATP requires the expenditure of an amount of exploration costs as determined by Queensland’s Department of Natural Resources, Mines and Energy (“Queensland DNRME”) and is subject to renewal every four years. Once a petroleum resource is identified, the holder of an ATP may apply for a petroleum lease, which provides the lessee with the ability to conduct additional exploration, development and production activities.

 

The Company is in correspondence with the Queensland DNRME about surface access issues on portions of ATP 526 and as a consequence is not certain of its 2004 work commitment for ATP 526.  The ATP 526 expenditure requirements net to the Company’s interest will be $3 million or less for a drilling program and $2 million or less for a seismic program.  The ATP 653 expenditure requirements net to the Company’s interest will be $3 million or less for a drilling program.  During 2004, ATPs 655 and 745 have expenditure requirements totaling approximately $1.4 million net to the Company’s interest.  The Company expects to meet these requirements by conducting seismic operations and exploratory drilling.  The 2004 expenditure requirements for ATPs 526, 655 and 745 must be met by October 31 and for ATP 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 the ATP for an additional four year exploratory period and generally requires the holder to relinquish a 20 percent portion of ATP acreage not held by a petroleum lease.  The Company is negotiating with the Queensland DNRME regarding petroleum leases that can be established on acreage that is part of ATP 526 and ATP 653.  The Company is preparing to negotiate with the Queensland DNRME regarding the amount of ATP 526 acreage that will be subject to the relinquishment provisions as its term expires October 31, 2004.

 

13

 

The Company’s gas marketing in eastern Australia is currently focused on obtaining long-term gas sales agreements that provide five to 15 years of firm sales typically starting in 2006 to 2008.  Short-term sales contracts for 2004 and 2005 are also being pursued.  Two short-term sales contracts have been recently signed, one for six months and one for 12 months. These contracts are expected to increase gas sales quantities in the near term as the Company prepares to escalate sales to 17 Bcf net or more per annum in 2008.  The Company anticipates spending approximately $30 million over the next three years on development drilling and expansion of delivery facilities to increase the Company’s annual deliverability to approximately 24 Bcf net by 2008.

 

The following table summarizes field development progress on the Comet Ridge project as of June 30, 2004.  In December 2003, the Company began using its second compression plant facility, which increased the field’s gas compression capacity to approximately 38 million cubic feet (“MMcf”) per day.

 

Comet Ridge Operations Review

 

 

The Company drilled two exploratory wells on the Comet Ridge project during the first half of 2004.  The 2004 drilling was substantially funded with borrowings from Slough Trading Estates Limited (“STEL”).  Future 2004 development and exploratory costs will be funded by a $150.0 million AUD senior credit facility described in Note 3 to the Consolidated Financial Statements.

 

During the first half of 2004, 100% of the Company’s gas sales in Australia were under a five-year contract effective June 1, 2000 with ENERGEX Retail Pty Ltd (“ENERGEX”), an unaffiliated customer.  The ENERGEX contract has delivery requirements of up to approximately 15,000 Mcf of gas per day.  In December 2002, the Company signed a gas supply term sheet with Origin Energy Retail Limited (“OERL”), a subsidiary of Origin Energy Limited, to supply approximately 9 Bcf per year, or approximately 25,000 Mcf of gas per day net to the Company’s interests, for 13 years beginning May 2007.  Origin Energy Limited is a large Australian integrated energy company which, through subsidiaries, owns nearly 24% of the Comet Ridge project.

 

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

 

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

 

14

 

United States

 

Lay Creek — The Company holds a 50% working interest in Lay Creek, a coalseam gas project located in Moffat County, Colorado. The project includes various leasehold interests covering over 82,000 gross acres. Koch Exploration Company (“Koch”), an unaffiliated third party, holds the remaining 50% working interest and operates the project.  The Company is currently evaluating the gas and water production from two pilot areas drilled in 2001 and 2002 in order to determine economic viability of the production.  The Company and Koch drilled four additional pilot wells expanding one of the pilot areas during the period from December 2003 through February 2004 at a cost to the Company of $1.0 million.  The Company is currently producing gas and water from eight wells on the Lay Creek project.  Gas production on the project is approximately 300 Mcf per day.  The Company expects to begin selling Lay Creek gas near the end of 2004.

 

Frenchman — The Company holds a 25% interest in the Frenchman prospect in eastern Colorado.  Total gross acreage in the prospect is approximately 162,000 acres.  Kerr-McGee Rocky Mountain Corporation (“Kerr-McGee”) holds the remaining 75% interest and is the operator of the prospect.  During 2003, five wells were drilled on the Frenchman prospect.  Three of these wells were completed and two were plugged and abandoned.  In early 2004, the Company drilled two additional Frenchman wells in which Kerr-McGee elected not to participate and resulted in the Company having a 100% interest in these wells.  The Company believes one of these 100% wells will be a commercial producer and the Company will earn 100% of offsetting drill sites as set forth in the operating agreement the Company has with Kerr-McGee.  The Company plugged and abandoned the other well drilled.  In the first quarter of 2004, the Company recorded an asset impairment expense of $150,000 related to unsuccessful exploration costs incurred on wells on the Frenchman prospect.  Two additional 100% wells are planned to be drilled in the third quarter of 2004 at a cost to the Company of approximately $420,000.  In addition, two wells are expected to be drilled jointly by the Company and Kerr-McGee in 2004 at a cost to the Company of approximately $157,500.  The economics of connecting the successfully completed wells to nearby pipelines are currently being evaluated.

 

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

 

Stateline — The Company holds a 25% interest in the Stateline prospect in western Nebraska.  Total gross acreage in the prospect 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 conducted at a cost to the Company of approximately $100,000.  Further seismic operations and exploratory drilling may be conducted if the results of the current seismic survey are encouraging.

 

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

 

Nine Mile — The Company holds a 70% interest in the prospective acreage and 40% interest in the outlying acreage of the Nine Mile prospect, a conventional oil and gas exploration prospect, also located in Moffat County, Colorado, and serves as operator of the prospect.  The prospect comprises approximately 38,000 gross acres.  The Company is currently evaluating exploratory work performed in 2002 and 2003 and is seeking industry partners before resuming exploratory activity.

 

Financial Condition, Liquidity and Capital Resources

 

The Company had cash and cash equivalents of $1.6 million as of June 30, 2004, compared to approximately $3.0 million as of December 31, 2003.  The Company has funded operations, deferred loan costs associated with obtaining TOGA’s senior credit facility and capital expenditures 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’s senior credit facility.

 

15

 

The Company anticipates funding operations and capital expenditures in Australia for the remainder of 2004 using funds from a $150 million AUD (approximately $114 million USD) financing facility).  See Note 3 to the Consolidated Financial Statements.

 

The Company anticipates funding 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 to provide funds for working capital, board-approved capital expenditures and operations through April 2005.

 

In order to fund discretionary capital expenditures in 2004 in excess of these cash resources, the Company contemplates that it will require alternative sources of capital.  Potential additional sources of funding may include additional debt financings and asset sales.  With the sale of interests in its prospective acreage, the Company expects to generate cash to reduce its investment in individual projects.  However, in the event that sufficient funding cannot be obtained, the Company will be required to curtail planned expenditures and may have to sell additional acreage and/or relinquish acreage.

 

Net cash used by operating 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 last year.  The increase in net cash used for operations in the first half of 2004 compared with the same period in 2003 resulted primarily from (a) lower gas revenues (b) higher interest expense on debt 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 with Australia and New Zealand Banking Group Limited and BOS International (Australia) Limited.  The initial borrowings under the facility totaled $103.0 million AUD ($71.0 million US).  TOGA used $100.0 million AUD ($68.2 million US) to pay in full its borrowings from STEL and to pay debt issuance costs.  The balance of the credit facility will be used to fund TOGA’s share of development costs of the Comet Ridge coalseam gas project in Queensland, Australia.

 

The table below provides an analysis of capital expenditures of $9.4 million during the six months ended June 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 first six months of 2004 capital spending was $873,000 of capitalized interest expense associated with the Company’s Australian and domestic properties.  Capital expenditures for the first six months of 2004 were funded principally under TOGA’s credit facilities with STEL.

 

16

 

Results of Operations - Comparison of the Three Months Ended June 30, 2004 and 2003

 

The Company incurred a net loss of $3.5 million for the three months ended June 30, 2004 compared to a net loss of $1.6 million for the three months ended June 30, 2003.  The greater net loss for the three months ended June 30, 2004 was primarily due to interest expense on additional debt used to fund property exploration and development.  Additionally, during the three months ended June 30, 2003, the Company recorded a $3.1 million foreign currency exchange gain offset by a $2.2 million impairment of oil and gas properties.  The table below provides a comparison of operations for the three months ended June 30, 2004 with those of the prior year’s second quarter.  The table is intended to provide a comparative review of significant operational items.  Accordingly, nominal differences may exist from the amounts presented in the accompanying Consolidated Financial Statements.

 

		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

 

Revenues and Sales Volumes

 

The Company is currently selling its Australian gas under a five-year contract with delivery requirements of up to 15,000 Mcf of gas per day to Energex, an unaffiliated customer.  In 2003, the Company had two Energex contracts, one of which expired at the end of 2003, with combined delivery requirements of up to 20,300 Mcf of gas per day.  The reduction in gas delivery requirements of 5,300 Mcf per day was the principal cause for the 20% decline in gas volumes sold in Australia in the second quarter of 2004 compared with the same period in 2003.  The Company is actively pursuing long-term and short-term gas contracts to increase gas volumes sold.  Effective July 2004, the Company entered into two short-term contracts:  one for six 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 to the lower sales volumes, offset by an increase in the average sales price received and changes in exchange rates.  The 14% increase in average gas sales price in Australia is due primarily to favorable changes in exchange rates.

 

During the second quarter of 2004, the Company had minimal domestic revenue.  Domestic revenues and volumes in 2004 and 2003 relate to small, retained interests in properties producing in the Powder River Basin in Wyoming.

 

Costs and Expenses

 

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

 

Domestic operating expenses in the second quarter of 2004 and 2003 are principally attributable to the Lay Creek coal-seam gas project where the wells are in the dewatering phase.

 

General and administrative (“G&A”) expenses for the second quarter of 2004 increased 16% compared to the three months ended June 30, 2003.  This increase is attributed to higher employee and consulting costs associated with managing the Comet Ridge properties and continuing costs for the Tri-Star litigation.

 

Other Income (Expense)

 

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

 

18

 

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

 

The Company incurred a net loss of $8.0 million for the six months ended June 30, 2004 compared to a net loss of $4.3 million for the six months ended June 30, 2003.  The greater net loss for the six months ended June 30, 2004 was primarily due to (i) interest expense on additional debt used to fund property exploration and development, (ii) increased operating costs and (iii) increased general and administrative expenses.  Additionally, during the six months ended June 30, 2003, the Company recorded a $3.1 million foreign currency gain offset by a $2.2 million impairment of oil and gas properties.  The table below provides a comparison of operations for the six months ended June 30, 2004 with those of the prior year’s six-month period.  The table is intended to provide a comparative review of significant operational items. Accordingly, nominal differences may exist from the amounts presented in the accompanying Consolidated Financial Statements.

 

		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

 

Revenues and Sales Volumes

 

The Company is currently selling its Australian gas under a five-year contract with delivery requirements of up to 15,000 Mcf of gas per day to Energex, an unaffiliated customer.  In 2003, the Company had two Energex contracts, one of which expired at the end of 2003, with combined delivery requirements of up to 20,300 Mcf of gas per day.  The reduction in gas delivery requirements of 5,300 Mcf per day was the principal cause for the 27% decline in gas volumes sold in Australia in the first half of 2004 compared with the same period in 2003.  The Company is actively pursuing long-term and short-term gas contracts to increase gas volumes sold.  Effective July 2004, the Company entered into two short-term contracts: one for six 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 decreased by 10% due to the lower sales volumes, offset by an increase in the average sales price received and changes in exchange rates.  The 23% increase in average gas sales price in Australia is due primarily to favorable changes in exchange rates.

 

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

 

Costs and Expenses

 

Operating expenses in Australia increased 29% due to an increase in the number of producing wells and the addition of a second compressor facility which commenced operations in December 2003.  Australian oil and gas property DD&A expense decreased 22% due principally to lower sales volumes.

 

Domestic operating expenses in the first half of 2004 and 2003 were principally attributable to the Lay Creek coal-seam gas project where the wells are in the dewatering phase.

 

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

 

General and administrative (“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 and consulting costs associated with managing the Comet Ridge properties and continuing costs for the Tri-Star litigation.

 

Other Income (Expense)

 

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

 

 

Critical Accounting Policies

 

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

 

20

 

Item 3.           Quantitative and Qualitative Disclosure About Market Risk

 

Market risk is the potential loss arising from adverse changes in market rates and prices, such as foreign currency exchange, interest rates and commodity prices.  The Company does not use financial instruments to any degree to manage foreign currency, interest rate or commodity risk and does not hold or issue financial instruments to any degree for trading purposes.  At June 30, 2004, the Company was exposed to some market risk with respect to foreign currency, long-term debt, and natural gas prices; however, management did not believe such risk to be material.  The Company’s market risk, discussed in Item 7A in its Annual Report on Form 10-K for 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, we evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures over financial reporting pursuant to Rule 13a-15 and 15d-15 of the Securities Exchange Act of 1934. Based upon that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures over financial reporting are adequate and effective in timely alerting them to material information required to be included in this quarterly report on Form 10-Q.

 

Disclosure controls and procedures, no matter how well designed and implemented, can provide only reasonable assurance of achieving an entity’s disclosure objectives. The likelihood of achieving such objectives is affected by limitations inherent in disclosure controls and procedures. These limitations include the fact that human judgment in decision-making can be faulty and that breakdowns in internal control can occur because of human failures such as simple errors or mistakes or because of intentional circumvention of the established process.

 

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

 

21

 

PART II - OTHER INFORMATION

 

Item 1.             Legal Proceedings

 

                                                See Note 5 to the Consolidated Financial Statements under Part I - Item 1.

 

Item 2.             Changes in Securities

 

During the quarterly period ended June 30, 2004, the Company issued 5,000 shares of its common stock upon the exercise of options with a weighted average exercise price of $2.50 per share.  The issuance of these securities was deemed to be exempt from registration under Section 4(2) of the Securities Act of 1933 or Regulation D thereunder as a transaction by an issuer not involving a public offering.

 

Item 4.             Submission of Matters to a Vote of Security Holders

 

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

 

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

 

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

 

Item 6.             Exhibits and Reports on Form 8-K

 

(a)                                  Exhibits:

 

Filed in Part I

 

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

 

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

 

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

 

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

 

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

 

(b)                                 Reports on Form 8-K:

 

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

 

The Registrant filed a Form 8-K on June 30, 2004, under Items 5 and 7 whereby it furnished its press release announcing the Facilities Agreement on June 9, 2004 and related exhibit.

 

22

 

SIGNATURES

 

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

			Tipperary Corporation
			Registrant
Date:	August 16, 2004	By:	\s\ David L. Bradshaw
			David L. Bradshaw, President, Chief Executive Officer
			and Chairman of the Board of Directors
Date:	August 16, 2004	By:	\s\ Joseph B. Feiten
			Joseph B. Feiten, Chief Financial Officer and
			Principal Accounting Officer

 

23

 

EXHIBIT INDEX

 

 

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

 

 

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

 

 

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

 

 

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

 

24