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    March 31, 2005

 

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)

 

 

(303) 293-9379

(Issuer’s telephone number)

 

 

Indicate by check mark whether the registrant (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

 

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

 

 

 

TIPPERARY CORPORATION AND SUBSIDIARIES

 

 

Index to Form 10-Q

 

 

PART I.	FINANCIAL INFORMATION
	Item 1.	Financial Statements
		Consolidated Balance Sheets
		March 31, 2005 and December 31, 2004
		Consolidated Statements of Operations
		Three months ended March 31, 2005 and 2004
		Consolidated Statements of Stockholders’ Equity
		Three months ended March 31, 2005 and 2004
		Consolidated Statements of Cash Flows
		Three months ended March 31, 2005 and 2004
		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.	Unregistered Sales of Equity Securities and Use of Proceeds
	Item 6.	Exhibits
SIGNATURES
EXHIBIT INDEX

 

 

PART I - - FINANCIAL INFORMATION

 

Item 1.  Financial Statements

 

TIPPERARY CORPORATION AND SUBSIDIARIES

Consolidated Balance Sheets

(dollars in thousands except per share data)

(unaudited)

 

		March 31,			December 31,
		2005			2004
ASSETS
Current assets:
Cash and cash equivalents		$	401		$	3,698
Receivables		2,129			2,156
Other current assets		314			436
Total current assets		2,844			6,290
Property, plant and equipment, at cost:
Oil and gas properties, full cost method		149,014			145,141
Other property and equipment		4,008			3,943
		153,022			149,084
Less accumulated depreciation, depletion and amortization		(10,454		)	(9,833		)
Property, plant and equipment, net		142,568			139,251
Debt issuance costs		5,030			4,661
Other noncurrent assets		451			482
		$	150,893		$	150,684
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	1,851		$	1,664
Accrued liabilities		3,206			1,881
Royalties payable		222			193
Total current liabilities		5,279			3,738
Long-term debt-related parties		18,000			17,000
Long-term debt		92,237			91,352
Future loan underwriting fees		670			—
Long-term asset retirement obligation		287			273
Commitments and contingencies (Note 6)
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;
41,365,594 shares issued and 41,355,994 shares outstanding as of March 31, 2005 and December 31, 2004, respectively		827			827
Capital in excess of par value		158,367			158,360
Accumulated deficit		(132,314		)	(128,653		)
Accumulated other comprehensive income		7,565			7,812
Treasury stock, at cost; 9,600 shares		(25		)	(25		)
Total stockholders’ equity		34,420			38,321
		$	150,893		$	150,684

 

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
		March 31,
		2005			2004
Revenues		$	3,375		$	1,168
Costs and expenses:
Operating		2,005			1,394
Depreciation, depletion and amortization		704			251
Asset retirement obligation accretion		9			9
Impairment of oil and gas properties		—			150
General and administrative		2,188			2,044
Total costs and expenses		4,906			3,848
Operating loss		(1,531		)	(2,680		)
Other income (expense):
Interest and other income		39			38
Interest expense		(2,174		)	(2,136		)
Foreign currency exchange gain (loss)		5			(3		)
Total other expense		(2,130		)	(2,101		)
Loss before income taxes		(3,661		)	(4,781		)
Income tax benefit		—			—
Loss before minority interest		(3,661		)	(4,781		)
Minority interest in loss of subsidiary		—			355
Net loss		$	(3,661	)	$	(4,426	)
Net loss per share-basic and diluted		$	(.09	)	$	(.11	)
Weighted average shares outstanding-basic and diluted		41,356			39,321

 

See accompanying notes to Consolidated Financial Statements.

 

2

 

TIPPERARY CORPORATION AND SUBSIDIARIES

Consolidated Statements of Stockholders’ Equity

(in thousands)

(unaudited)

 

		Common Stock					Capital in excess of			Accumulated			Accumulated Other Comprehensive			Treasury Stock
		Shares		Amount			par value			Deficit			Treasury Stock			Shares		Amount				Total
Balance at December 31, 2003		39,221		$	785		$	149,970		$	(113,315	)	$	7,094		10		$	(25	)		$		44,509
Warrants granted for services		—		—			56			—			—			—		—				56
Common stock issued:
Stock options exercised		100		2			273			—			—			—		—				275
Comprehensive loss:
Net loss		—		—			—			(4,426		)	—			—		—				(4,426			)
Foreign currency translation adjustment		—		—			—			—			480			—		—				480
Total comprehensive loss																						(3,946			)
Balance at March 31, 2004		39,321		$	787		$	150,299		$	(117,741	)	$	7,574		10		$	(25	)		$		40,894
Balance at December 31, 2004		41,356		$	827		$	158,360		$	(128,653	)	$	7,812		10		$	(25	)		$		38,321
Warrants granted for services		—		—			7			—			—			—		—				7
Comprehensive loss:
Net loss		—		—			—			(3,661		)	—			—		—				(3,661			)
Foreign currency translation adjustment		—		—			—			—			(247		)	—		—				(247			)
Total comprehensive loss																						(3,908			)
Balance at March 31, 2005		41,356		$	827		$	158,367		$	(132,314	)	$	7,565		10		$	(25	)		$		34,420

 

See accompanying notes to Consolidated Financial Statements.

 

3

 

TIPPERARY CORPORATION AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(in thousands)

(unaudited)

 

		Three months ended
		March 31,
		2005			2004
Cash flows from operating activities:
Net loss		$	(3,661	)	$	(4,426	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		704			251
Amortization of debt issuance costs		266			127
Warrants granted for services		7			56
Minority interest in loss of subsidiary		—			(355		)
Asset retirement obligation accretion		9			9
Impairment of oil and gas properties		—			150
Accrued interest added to principal		1,660			—
Changes in current assets and current liabilities:
Decrease in receivables		27			182
Decrease in other current assets		122			131
Increase (decrease) in accounts payable and accrued liabilities		(261		)	169
Increase (decrease) in royalties payable		29			(4		)
Net cash used in operating activities		(1,098		)	(3,710		)
Cash flows from investing activities:
Capital expenditures		(3,282		)	(4,209		)
Net cash used in investing activities		(3,282		)	(4,209		)
Cash flows from financing activities:
Proceeds from exercise of common stock options		—			275
Proceeds from borrowings		1,544			7,568
Principal repayments		(470		)	—
Debt issuance costs		23			(495		)
Net cash provided by financing activities		1,097			7,348
Effect of exchange rate changes on cash		(14		)	(116		)
Net decrease in cash and cash equivalents		(3,297		)	(687		)
Cash and cash equivalents at beginning of period		3,698			2,996
Cash and cash equivalents at end of period		$	401		$	2,309

 

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 this quarterly report on Form 10-Q, unless the context requires otherwise, when we refer to “we,” “us,” “our,” “Tipperary,” and “the Company,” we are describing Tipperary Corporation and its subsidiaries on a consolidated basis.

 

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 at March 31, 2005, and the results of their operations for the three-month periods ended March 31, 2005 and 2004 and their cash flows for the three-month periods ended March 31, 2005 and 2004. The Consolidated Financial Statements include the accounts of Tipperary Corporation and its wholly-owned subsidiaries, Tipperary Oil and Gas Corporation, Tipperary CSG, Inc., Tipperary Queensland, Inc. and Burro Pipeline Corporation, and its 90%-owned subsidiary, Tipperary Oil and Gas (Australia) Pty Ltd (“TOGA”).  All intercompany transactions and balances have been eliminated in consolidation.  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, 2004.  These financial statements should be read in conjunction with the Form 10-K.

 

Impact of New Accounting Pronouncements

 

In December 2004, the Financial Accounting Standards Board (“FASB”)  issued a revision to SFAS No. 123, “Accounting for Stock-Based Compensation,” SFAS No. 123R, “Share-Based Payment.” SFAS No. 123R focuses primarily on transactions in which an entity exchanges its equity instruments for employee services and generally establishes standards for the accounting for transactions in which an entity obtains goods or services in share-based payment transactions and is required to expense the value of employee stock options and similar awards.  The Securities and Exchange Commission recently delayed the implementation date for this pronouncement.  The Company now expects to adopt SFAS No. 123R effective January 1, 2006 using the modified prospective application.  The Company does not expect SFAS No. 123R to have a material effect on the Company’s Consolidated Financial Statements.

 

We have reviewed all other recently issued, but not yet adopted, accounting standards in order to determine their effects,  if any, on our results of operations or financial position.  Based on that review, we believe that none of these pronouncements will have a significant effect on our current or future financial position or results of operations.

 

Revenue Recognition and Gas Imbalances

 

The Company recognizes natural gas revenue from its interests in producing wells as natural gas is 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. If excess takes of natural gas exceed the Company’s remaining proved reserves for the property it records a natural gas imbalance in other liabilities.  As of March 31, 2005  the Company had taken and sold more than its share of natural gas volumes produced from the Comet Ridge project and was overproduced by approximately 1,761 MMcf (net of royalties). Based on the March 31, 2005 average sales price of $1.95 per Mcf, this overproduction represents approximately $3.4 million in gas revenues. At March 31, 2005, no liability has been recorded for the excess volumes taken, as they did 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 TOGA’s entitled share of sales, to enable underproduced parties to sell more than their entitled share of the gas sales and cure the imbalance.

 

5

 

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 March 31, 2005, 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 a director or employee must pay to acquire the stock.  Pro forma results as if the Company had adopted the cost recognition provisions of SFAS Nos. 148 and 123 are presented below:

 

		Three Months Ended March 31,
		2005			2004
		(in thousands, except per share data)
Net loss, as reported		$	(3,661	)	$	(4,426	)
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		(117		)	(16		)
Pro forma net loss		$	(3,778	)	$	(4,442	)
Loss per share
Basic and diluted—as reported		$	(.09	)	$	(.11	)
Basic and diluted—pro forma		$	(.09	)	$	(.11	)

 

 

Foreign Currency

 

The functional currency of TOGA is the Australian dollar. As the functional currency is the local currency, the current rate method is used to translate TOGA’s Australian dollar financial statements into U.S. dollars. 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 because of the Company’s net operating loss carryforwards) as of March 31, 2005 and December 31, 2004 totaled $7.6 million and $7.8 million, respectively.

 

Liquidity and Operations

 

The Company anticipates funding operations and capital expenditures in Australia and the United States for 2005 using (a) cash on hand at March 31, 2005, (b) net gas revenues, (c) approximately $25 million ($32 million AUD) in available long term borrowings from the Company’s Australian senior credit facility and (d) a commitment from Slough to provide funds for operations, working capital and board-approved capital expenditures through April 2006.  The Company’s majority shareholder, Slough Estates USA Inc. (“Slough”), intends to divest all or a portion of its ownership interest in the near term.  While Slough has committed to support the Company with long-term loans or equity contributions through April 2006, the Company does not know what alternative financing or equity investments will be available from other parties after any divestiture occurs.  Any alternative financing the Company may obtain after Slough’s divestiture could have terms less favorable than current terms provided by Slough.

 

6

 

The Company anticipates having sufficient production history from its Frenchman and Republican project wells by late 2005 which should allow the Company to be able to support a limited amount of borrowing for further development of these projects or partial repayment of existing Slough debt. In order to fund discretionary domestic capital expenditures in 2005 in excess of these cash resources, the Company anticipates that it will require alternative sources of capital. Additional sources of funding may include additional debt financings and asset sales.  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 March 31, 2005, the Company owed Slough and Slough Trading Estates Limited (“STEL”), a United Kingdom company that is the parent of Slough, approximately $18.0 million.

 

As of March 31, 2005, the Company had one credit facility agreement with STEL with an outstanding balance of $13.0 million.  No additional funds may currently be borrowed under this facility.  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 on 18-months notice.  So long as the STEL indebtedness exists, the Company may not obtain any additional third party indebtedness, either secured or unsecured, or make a priority payment of any obligation, without first obtaining written approval from STEL.

 

In 2002 and in the first quarter of 2005, the Company borrowed $4 million and $1 million, respectively, from Slough which is evidenced by a note payable dated May 13, 2005 that bears interest at LIBOR plus 3.5% (6.22% as of March 31, 2005) and is payable in full on April 30, 2006.  The note also relates to an additional $4.4 million to be borrowed in the second quarter of 2005.

 

Slough Estates plc, STEL’s parent, has guaranteed for a period up to five years through June 2009 the Company’s $150.0 million AUD bank credit facility  that closed in June 2004.  As consideration for the guarantee, the Company pays 1% per annum on the daily outstanding balance of the debt guaranteed.  For the three month period ended March 31, 2005, the Company paid guarantee fees of $221,000.

 

For the three month periods ended March 31, 2005 and 2004, approximately $484,000 and $2.4 million, respectively, in interest and fees were paid collectively to Slough and STEL under the financing agreements discussed herein.

 

Slough has committed to provide funds to the Company in the form of long-term loans or equity contributions through April 2006 to be used for operations, working capital and board-approved capital expenditures.

 

NOTE 3 – COMET RIDGE PROJECT FINANCING

 

On June 9, 2004, TOGA entered into a $150.0 million AUD senior credit facility agreement comprised of a recourse portion and a non-recourse portion with two major Australian financial institutions for the purpose of paying in full TOGA’s borrowings of $100.0 million AUD from STEL and to fund TOGA’s operations and its 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 (6.34% per annum as of March 31, 2005) varies with the Australian inter-bank rate plus other factors.  Commitment fees of 0.425% per annum of committed but undrawn funds, as defined by the credit facility, are payable semi-annually.  The facility is collateralized by, among other things, TOGA’s common stock and virtually all of the Company’s consolidated interest in the Comet Ridge project and is guaranteed through June 9, 2009 by Slough Estates plc (See Note 2).  The facility contains certain restrictive covenants, including maintenance of certain ratios. While Slough is guaranteeing the full debt, as it was at March 31, 2005, the Company’s covenant obligations relate primarily to reporting requirements.  At March 31, 2005, the Company had met all required covenants.  When all or a portion of the debt is no longer guaranteed, the Company will be obligated to maintain certain financial ratios in addition to the current reporting requirement covenants.  The U.S. dollar value of the outstanding balance of this facility as of March 31, 2005 was approximately $92.2 million (approximately $119 million AUD), including interest due which will be paid with funds borrowed from the facility of $1.7 million (approximately $2.1 million AUD).  TOGA incurred approximately $4.8 million in debt issuance costs on this facility, which TOGA has deferred and is amortizing over five years.  TOGA has accrued an additional $670,000 for the present value of deferred underwriting fees to be paid by June 9, 2009.  These costs relate to future loan underwriting fees the Company will pay upon conversion of the senior credit

 

7

 

facility from recourse to non-recourse debt.  During the first quarter of 2005, TOGA paid interest and commitment fees of approximately $128,000 and $-0-, respectively on this facility and added $1,660,000 of accrued interest to the principal of this facility.

 

NOTE 4 - LOSS PER SHARE

 

The following table sets forth the computation of basic and diluted loss per share (“EPS”) (in thousands except per share data):

 

		Three Months Ended March 31,
		2005			2004
Numerator:
Net loss		$	(3,661	)	$	(4,426	)
Denominator:
Weighted-average shares outstanding		41,356			39,321
Effect of dilutive securities:
Assumed exercise of dilutive options and warrants		—			—
Weighted-average shares and dilutive potential common shares		41,356			39,321
Basic and diluted loss per share		$	(.09	)	$	(.11	)
Total options and warrants which could potentially dilute basic EPS in future periods		3,929			3,523

 

NOTE 5 – MINORITY INTEREST IN TOGA

 

For the three month period ended March 31, 2005, the 10% minority interest share of TOGA’s net loss totaled $166,000.  As the minority interest in TOGA’s net equity (excluding the cumulative foreign currency translation adjustment), at December 31, 2004 was zero, the Company recognized 100% of TOGA’s net loss for the quarter. The entire minority interest share of TOGA’s net loss was recognized by the Company.  The Company will continue recognizing 100% of TOGA’s net losses until TOGA becomes profitable.  The Company will record 100% of TOGA’s net income until it has recouped the minority interest’s share of TOGA’s net losses. Such share totaled $901,000 at March 31, 2005.

 

8

 

NOTE 6 - COMMITMENTS AND CONTINGENCIES

 

The Company’s business activities are subject to federal, state and local environmental laws and regulations as well as similar laws and regulations in the Commonwealth of Australia and the State of Queensland, Australia. In the fourth quarter of 2003, the Queensland government notified the Company that exploration and production of gas from under national park lands would be limited to using surface facilities located outside the parks. If gas reserves are discovered under park lands, they would be recovered to the extent possible using directional drilling from drill sites adjacent to park lands. Directional drilling is currently used to produce some coalseam and conventional gas in the U.S. and Australia.  Management believes  the technique can be used effectively at Comet Ridge to recover a substantial portion of any reserves that ultimately would have been recoverable from drilling within the parks.  During 2005 the Company has drilled two horizontal wells and is evaluating the effectiveness of the drilling.  Management does not expect these new requirements to significantly increase future exploration, development and operating costs per Mcf sold. Three of the Company’s productive wells and one ATP 526 exploration well were previously permitted on park lands. Under current government policy, the four wells are to be plugged and abandoned, and the surface area reclaimed at an estimated cost to the Company of $100,000. The Company expects to recover these wells’ reserves using directional drilling. The amount of any reserves that may ultimately be determined to be under park lands is not currently known. The Company will continue to monitor environmental compliance. There can be no assurance that environmental laws and regulations will not become more stringent in the future or that the Company will not incur significant costs in the future to comply with such laws and regulations.

 

The Company is subject to various other possible contingencies which arise primarily from interpretation of federal and state laws and regulations affecting the oil and gas industry. Although management believes it has complied with the various laws and regulations, administrative rulings and interpretations thereof, additional costs could be incurred as new interpretations and regulations are issued.

 

NOTE 7 - 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.  General and administrative expense, 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 March 31, 2005 and 2004, and for the three months ended March 31, 2005 and 2004 is as follows (in thousands):

 

As of and for the three months ended March 31, 2005

 

											Non- Segmented Items(1)			Total
		Gas and Oil Operations
		Australia			United States			Total
Revenues		$	3,374		$	1		$	3,375		$	—		$	3,375
Income (loss) before income taxes		$	1,110		$	(402	)	$	708		$	(4,369	)	$	(3,661	)
Property, plant and equipment, net		$	130,123		$	11,950		$	142,073		$	495		$	142,568

(1)    Income (loss) before income taxes reconciling items include $2.2 million of general and administrative expenses, $51,000 of corporate depreciation and $2.2 million of interest expense.  Property, plant and equipment, net, includes $495,000 of corporate office equipment, computer hardware and software.

 

9

 

As of and for the three months ended March 31, 2004

 

													Non- Segmented Items(1)			Total
		Gas and Oil Operations
		Australia					United States			Total
Revenues		$			1,166		$	2		$	1,168		$	—		$	1,168
Loss before income taxes		$		(215		)	$	(407	)	$	(622	)	$	(4,159	)	$	(4,781	)
Property, plant and equipment, net		$	113,903				$	7,510		$	121,413		$	421		$	121,834

(1)    Loss before income taxes reconciling items include $2.0 million of general and administrative expenses, $14,000 of corporate depreciation and $2.1 million of interest expense.  Property, plant and equipment, net, includes $421,000 of corporate office equipment, computer hardware and software.

 

NOTE 8 – PROPERTY, PLANT AND EQUIPMENT

 

A summary of property, plant and equipment follows:

 

		March 31, 2005			December 31, 2004
		(in thousands)
Evaluated oil and gas properties:
Australian properties		124,590			121,376
Domestic properties		2,335			2,068
Unevaluated oil and gas properties:
Australian properties		12,474			13,236
Domestic properties		9,615			8,461
Oil and gas properties		149,014			145,141
Other property and equipment		4,008			3,943
		153,022			149,084
Less accumulated depreciation, depletion and amortization		(10,454		)	(9,833		)
Property, plant and equipment, net		$	142,568		$	139,251

 

 

NOTE 9 – STATEMENT OF CASH FLOWS SUPPLEMENTAL INFORMATION

 

		Three Months Ended March 31,
		2005			2004
		(in thousands)
Cash paid during the period for interest		$	572		$	2,418
Non-cash investing and financing activities—
Net increase in payables for capital expenditures		$	1,774		$	177

 

10

 

Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

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 we expect or anticipate 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, we undertake 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 our SEC filings, particularly our Form 10-K for the year ended December 31, 2004, for meaningful cautionary language and discussion of risk factors disclosing why actual results may vary materially from those anticipated by management.

 

Overview

 

Australia

 

Our activities in Australia are conducted substantially through our 90%-owned Australian subsidiary, Tipperary Oil & Gas (Australia) Pty Ltd (“TOGA”).  As of March 31, 2005, Tipperary owned a 75.25% undivided capital-bearing interest in the Comet Ridge project in Queensland, Australia.  Of this interest TOGA holds 65% and other Tipperary entities hold 10.25%.  This project comprises approximately 1,230,500 acres in the Bowen Basin, which includes five petroleum leases (“PL”) covering approximately 287,500 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.  We also hold 100% of ATP 655, which is near the Comet Ridge project and covers approximately 77,000 acres.

 

An ATP allows the holder to undertake a range of exploration activities, including geophysical surveys, field mapping and exploratory drilling. Each ATP requires the expenditure of an amount of exploration costs as determined by Queensland’s Department of Natural Resources and Mines (“Queensland DNRM”) and is generally 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.

 

Upon expiration of an ATP, legislation and policy of the Queensland DNRM allow the ATP holder to apply to renew the ATP for an additional four year period.  ATP 526 was renewed effective November 1, 2004 for another four year exploration term, expiring on October 31, 2008.  No relinquishment was required at the time of renewal, however a series of relinquishments are mandatory during the current term. Recent changes to legislation have changed several fundamental aspects of ATP management, especially those concerning relinquishment and the ability to vary conditions of an ATP.  These changes have also resulted in Tipperary’s acreage being administered under different Acts.  ATP 526, and all the Petroleum Leases, are administered under the Petroleum Act 1923 as before, except that the Act has been substantially amended effective December 31, 2004.  ATPs 653, 655 and 745 which have initial terms expiring on September 30, 2006, October 31,  2007 and October 31, 2007 respectively, are now administered under the Petroleum and Gas (Production and Safety) Act 2004, which was enacted on December 31, 2004.  Renewal of these ATPs can be for a 12 year period under the new Act, when renewal becomes due.

 

With respect to ATP 653, we filed and received a variance to combine year two expenditure requirements with those of year three and to drill a horizontal well, eliminating the obligation to drill two conventional wells. The horizontal well was partially drilled in January 2005, and we anticipate drilling operations to continue in late 2005.  We have completed expenditure requirements for ATPs 745 and 655.  The terms of the ATP 526 renewal do not require exploration expenditures during 2005.

 

Our gas marketing in eastern Australia has been primarily focused on obtaining long-term gas sales agreements that provide five to 15 years of firm sales typically starting in 2006 to 2008.  However, short-term sales contracts have recently

 

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been utilized and are being pursued.  During 2004, our Australian natural gas sales were made to four purchasers under various short and long-term contracts.  We are under contract to provide gas volumes to the same four purchasers in 2005.

 

The following tables summarize gross gas production by quarter and well status on the Comet Ridge project as of March 31, 2005.  We are expanding the capacity of our metering equipment, compressors and facilities to a sales capacity of approximately 45 MMcf per day by mid-year 2005.

 

Comet Ridge Operations Review

 

		For the Quarter Ended
		June 30, 2004		September 30, 2004		December 31, 2004		March 31, 2005
Gross Average Daily Volumes (MMCF)
Sold		15		23		28		28
Flared		4		2		1		1
Used for compression fuel		2		3		3		3
Produced		21		28		32		32

 

		Number of Wells At March 31, 2005
Well Status
Selling•		49
Dewatering or temporarily shut-in		27
Producing		76
Being evaluated		24
Injection/monitoring wells		2
To be plugged and abandoned		2
Plugged and abandoned		3
Total drilled		107

 

We drilled one exploratory and one development well on the Comet Ridge project during the first quarter of 2005.  Both of these wells were drilled horizontally.  The development well was successfully completed, and it tested over one million cubic feet of gas per day.  Drilling of the exploratory well was interrupted by difficulties encountered while drilling.  We expect this well will be re-entered in late 2005.  The 2005 drilling was substantially funded with borrowings from the Australian bank credit facility.

 

In December 2004, we signed a 23-month extension to the five-year Energex Retail Pty Ltd (“Energex”) gas supply contract.  The extension expires on April 30, 2007.  The new contract is similar in terms to the existing contract.  On December 23, 2004, we entered into an agreement to supply gas to Orica Australia Pty Ltd (“Orica”), an unrelated party.  The contract commences on June 26, 2006 for a term of 10 years and provides that Orica will purchase a minimum of 3,000 and a maximum of 4,800 Mcf of gas per day.  On December 30, 2004, we entered into an agreement to supply natural gas to Santos QNT Pty Ltd (“Santos”).  The contract began on January 1, 2005 for a term of 21 months and provides that Santos will purchase a minimum of 7,700 and a maximum of 9,700 Mcf of gas per day.  We have entered into additional agreements with Energex and CS Energy whereby they may purchase gas under spot sale arrangements.  We have a gas sales agreement with Origin Energy Retail Limited (“OERL”), a subsidiary of Origin Energy Limited, to supply approximately 9 Bcf per year, or approximately 25,000 Mcf of gas per day net to the Company’s interest, 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.  All of the third party working interest owners in the Comet Ridge project have elected to participate in the sales agreement we entered into with OERL and the sales agreements entered into with Energex, Orica and Santos in December 2004.

 

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We believe that current and anticipated development drilling programs on the Comet Ridge project will enable it to satisfy its gas supply delivery commitments, although this cannot be assured.

 

United States

 

Our assets in the United States consist primarily of natural gas exploration and development leaseholds in Colorado and Nebraska, which are described below by project area.  The four projects in eastern Colorado and western Nebraska principally target conventional, natural gas in the Niobrara formation.

 

Frenchman — We hold a 25% interest in 159,000 acres and 100% in 3,000 acres in the Frenchman project in eastern Colorado.  The Houston Exploration Company (“Houston Exploration”) holds the remaining 75% interest in the 159,000 acres and is the operator of that portion of the acreage.  As of May 1, 2005, we have drilled a total of 14 wells on the project.  We have successfully completed eleven wells in the 100%-owned area of the project and anticipate we will drill six additional 100%-owned wells in 2005 at a cost to us of approximately $1,200,000.  In February 2005, Tipperary completed a gas gathering system at a cost of approximately $350,000.  In late May 2005 we expect to begin selling gas from the four 100% wells which are connected.  We expect the June 2005 net sales volumes to approximate 1.4 MMcf per day.  We also expect five additional 100% wells to be connected to the gathering system by June 30, 2005.  With additional compression capacity and future drilling, net sales volumes are expected to be approximately 3 MMcfd later in 2005.

 

Republican — We hold a 20% interest in the Republican project in eastern Colorado.  Total gross acreage in this project approximates 170,000 acres. Houston Exploration holds the remaining 80% interest and is the operator of the project.  Through May 1, 2005, a total of 39 wells have been drilled on the project of which 32 wells were completed and seven were plugged and abandoned.  An additional 15 wells are planned to be drilled in the second quarter of 2005 at an estimated net cost to us of $600,000.  In the first quarter of 2005, we participated with Houston Exploration in a 3D seismic program covering 99,000 gross acres at a net cost to us of $726,000.  We expect gas sales to begin in mid 2005.

 

Lay Creek — We hold a 50% working interest in Lay Creek, a coalseam gas project in western Colorado. The project includes various leasehold interests covering over 92,000 gross acres. Koch Exploration Company (“Koch”) holds the remaining 50% working interest and operates the project.  We are currently evaluating the gas and water production from pilot wells in order to determine economic viability of the production.  We are investigating pipeline connections and are evaluating the possibility of selling gas in 2005.  We are also showing the acreage to other companies which may have an interest in participating in future drilling.

 

Stateline — We hold a 25% interest in the Stateline project in western Nebraska.  Total gross acreage in the project is approximately 113,000 acres.  Lance Oil & Gas Company, Inc. (“Lance”) holds the remaining 75% interest and is the operator of the project.  In the first half of 2004, preliminary 2-D seismic operations were conducted at a cost to us of approximately $100,000.  The acquisition of 3D seismic data began in February 2005 at a cost to us of approximately $160,000.  We have identified drill sites through the seismic evaluation and anticipate drilling will begin in the third quarter of 2005.

 

Sand Hill — During late 2003, we acquired leasehold acreage in western Nebraska totaling approximately 51,000 gross acres, the “Sand Hill” project.  This acreage is located in the vicinity of our Frenchman, Republican and Stateline projects. We currently hold 100% of the acreage but may sell an interest to an industry partner.  Alternatively, we may elect to explore and develop this project independently.  During the fourth quarter of 2004, we conducted limited 2-D seismic operations on the Sand Hill project and are currently evaluating those results.

 

Financial Condition, Liquidity and Capital Resources

 

We had cash and cash equivalents of $401,000 as of March 31, 2005, compared to approximately $3.7 million as of December 31, 2004.  We have funded operations and capital expenditures for the three months ended March 31, 2005, using primarily (a) $3.7 million of cash on hand  at December 31, 2004, (b) borrowings from our Australian senior credit facility and (c) borrowings from Slough.

 

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We anticipate funding operations and capital expenditures in Australia and the United States for 2005 using (a) cash on hand at March 31, 2005, (b) net gas revenues, (c) approximately $25 million ($32 million AUD) in available long term borrowings from our Australian senior credit facility and (d) a commitment from Slough to provide funds for operations, working capital, and board-approved capital expenditures through April 2006.  Our majority shareholder, Slough intends to divest all or a portion of its ownership interest in the near term.  While Slough has committed to support us with long-term loans or equity contributions through April 2006, we do not know what alternative financing or equity investments will be available from other parties after any divestiture occurs.  Any alternative financing we may obtain after Slough’s divestiture could have terms less favorable than current terms provided by Slough.

 

We anticipate having sufficient production history from our Frenchman and Republican project wells by late 2005 to be able to borrow against these assets.  In order to fund discretionary domestic capital expenditures in 2005 in excess of these cash resources, we anticipate that we will require alternative sources of capital. Additional sources of funding may include additional debt financings and asset sales.  However, in the event that sufficient funding cannot be obtained, we 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 $1.1 million during the three months ended March 31, 2005, compared to $3.7 million of cash used during the same period last year.  The decrease in net cash used for operations in the first quarter of 2005 compared with the same period in 2004 resulted primarily from higher gas revenues.

 

The table below provides an analysis of cash used for capital expenditures during the three months ended March 31, 2005.

 

Capital Expenditures Activity

(in thousands)

 

Australia:
Comet Ridge drilling and completion		1,887
Comet Ridge facilities and equipment		298
ATP 655 exploration		217
Other		30
Domestic:
Republican drilling and completion		332
Frenchman facilities, equipment and drilling		291
Stateline seismic acquisition		103
Other		124
Total		$	3,282

 

Included within the first quarter 2005 capital spending was $253,000 of capitalized interest expense associated with our Australian and domestic properties.  Capital expenditures for the first quarter in 2005 were funded principally under TOGA’s credit facility with Australian financial institutions.

 

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The Company has various commitments in addition to its long-term debt.  The following table summarizes the Company’s contractual obligations at March 31, 2005 (in thousands):

 

Contractual Obligation		Total			2005			2006			2007			2008			Thereafter
Long-term debt(1)		$	110,237		$	—		$	5,000		$	—		$	—		$	105,237
Interest(2)		$	54,368		$	5,908		$	7,824		$	8,058		$	8,250		$	24,328
Operating leases for office space		$	1,507		$	255		$	363		$	370		$	247		$	272
Operating leases for equipment		$	5,464		$	1,073		$	1,250		$	1,215		$	1,102		$	824
Petroleum lease expenditures(3)		$	2,035		$	935		$	550		$	275		$	275		$	—

(1)     Senior credit facility and debt payable to Slough and STEL.

(2)     Based on March 31, 2005 weighted average interest rate of 6.34% and anticipated debt repayment.

(3)     Petroleum lease expenditures can be reduced or eliminated by governmental royalties paid on gas sales.

 

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Results of Operations - Comparison of the Three Months Ended March 31, 2005 and 2004

 

We incurred a net loss of approximately $3.7 million for the three months ended March 31, 2005 compared to a net loss of approximately $4.4 million for the three months ended March 31, 2004.  The lower net loss for the three months ended March 31, 2005 was primarily due to higher gas revenues, partially offset by higher operating costs and depreciation, depletion and amortization.  The table below provides a comparison of operations for the three months ended March 31, 2005 with those of the prior year’s 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.  Certain prior period amounts may have been reclassified to ensure comparability.

 

		Three Months Ended March 31,
		2005			2004			Increase (Decrease)			% Increase (%Decrease)
		($ in thousands, except average per Mcf prices and costs)
Worldwide operations:
Gas revenue		$	3,375		$	1,168		$	2,207		189	%
Gas volumes (MMcf)		1,732			651			1,081			166	%
Average gas price per Mcf		$	1.95		$	1.79		$	0.16		9	%
Operating expenses		$	2,005		$	1,394		$	611		44	%
Average operating costs per Mcf sold		$	1.16		$	2.14		$	(0.98	)	(46	)%
General and administrative		$	2,188		$	2,044		$	144		7	%
Depreciation, depletion and amortization (“DD&A”)		$	704		$	251		$	453		180	%
Impairment		$	—		$	150		$	(150	)	(100	)%
Interest expense		$	2,174		$	2,136		$	38		2	%
Australia operations:
Gas revenue		$	3,374		$	1,166		$	2,208		189	%
Gas volumes (MMcf)		1,732			650			1,082			166	%
Average gas price per Mcf		$	1.95		$	1.79		$	0.16		9	%
Operating expenses		$	1,608		$	1,140		$	468		41	%
Average operating costs per Mcf sold		$	0.93		$	1.75		$	(0.82	)	(47	)%
Oil and Gas property DD&A		$	653		$	203		$	450		222	%
Other DD&A		$	37		$	35		$	2		6	%
Oil and Gas DD&A rate per Mcf sold		$	0.38		$	0.31		$	0.07		23	%
Domestic operations:
Gas revenue		$	1		$	2		$	(1	)	(50	)%
Gas volumes (MMcf)		—			1			(1		)	(100	)%
Average gas price per Mcf		$	5.31		$	4.00		$	1.31		33	%
Operating expenses		$	397		$	254		$	143		56	%
Average operating costs per Mcf sold(1)		$	5.41		$	2.27		$	3.14		138	%
Impairment		$	—		$	150		$	(150	)	(100	)%
Other DD&A		$	14		$	14		$	—		0	%

(1)          Average operating costs per Mcf for the quarter is for our sole producing property.  For a more meaningful comparison of operating costs per Mcf, significant operating costs associated with non-producing properties in the dewatering stage have been excluded.

 

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