ITEM 3. LEGAL PROCEEDINGS
Until December of 2004, we and two unaffiliated working interest owners were 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 ("Tri-Star litigation"). The plaintiffs alleged, among other matters, that Tri-Star and/or the individual defendants failed to operate the project in a good and workmanlike manner and committed various other breaches of a joint operating contract, breached a previous mediation agreement, committed certain breaches of fiduciary and other duties owed to the plaintiffs, and committed fraud in connection with the project. Tri-Star answered the allegations, and filed amended pleadings denying liability and raising a number of affirmative defenses and asserting various counterclaims. TOGA operated the project beginning in March 2002, after the court entered a 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.
On October 30, 2004, we entered into a settlement agreement with Tri-Star covering this litigation, as well as all other litigation between those parties originating in Queensland, Australia. Pursuant to the settlement agreement we will continue as operator, and Tri-Star has transferred to us 96% and two unrelated intervening plaintiffs the remaining 4% of each of the registered titles for the Comet Ridge project held in its name, including, but not limited to, the relevant Authorities to Prospect and Petroleum Leases. Tri-Star has transferred to a newly-formed subsidiary of Tipperary Corporation, Tipperary Queensland, Inc., a 2.25% working interest in the Comet Ridge project, subject to a contractual overriding royalty interest that approximates 2.5% of Tipperary's future Comet Ridge revenues (net of pipeline tariffs) and is equivalent to 1.5% of all Comet Ridge gas produced and sold. The transfer of the registered titles has been completed. Under the settlement agreement we have paid $5.0 million to Tri-Star, using existing cash and TOGA's Australian loan facility. In addition to other provisions, the settlement agreement provides that all claims made by us, Tri-Star and the individual defendants are to be dismissed without ability to refile. The order actually dismissing the claims was signed on December 15, 2004. We, the individual defendants and Tri-Star have each released each other from liability for any claims that were or could have been asserted in the litigation, whether known or unknown.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Our common stock is listed and has been trading on the American Stock Exchange since April 1992. As of March 9, 2005, there were approximately 1,600 holders of record of our common stock. The table below sets forth the high and low closing prices for the common stock of the Company for the periods indicated:
We have not paid any cash dividends on our common stock and do not expect to pay any dividends in the foreseeable future. We intend to retain any earnings to provide funds for operations and expansion of our business.
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
The table below provides certain information as of December 31, 2004 with respect to compensation plans under which our equity securities are authorized for issuance:
At December 31, 2004, we had 1,201,900 warrants outstanding to directors, employees and non-employees. From time to time, we have offered warrants to directors and employees as an incentive to provide long-term service to us. The terms of each warrant are negotiated. Less frequently, we have offered warrants to consultants as part of their compensation agreements.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The selected consolidated financial information presented below for the years ended September 30, 2000 through December 31, 2004 is derived from our Consolidated Financial Statements.
Sales and impairments of oil and gas properties, write-offs of deferred loan costs and impairments of oil and gas properties in certain years materially affect the comparability of the financial information presented below. This information should be read in conjunction with the Consolidated Financial Statements and associated Notes and Management's Discussion and Analysis of Financial Condition and Results of Operations.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
GENERAL
The following is a discussion of our financial condition and results of operations. This discussion should be read in conjunction with our Consolidated Financial Statements and the Notes thereto.
This discussion and analysis of financial condition and results of operations, and other sections of this Form 10-K, contain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are based on management's beliefs, assumptions, current expectations, estimates and projections about the oil and gas industry, the economy and about our Company. Words such as "may," "will," "expect," "anticipate," "estimate" or "continue," or comparable words are intended to identify the forward-looking statements. These statements are not guarantees of future performance and involve numerous risks, uncertainties and assumptions that are difficult to predict with regard to timing, extent, likelihood and degree of occurrence. Therefore, actual results and outcomes may materially differ from what may be expressed, projected or forecasted in the 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.
Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to, changes in our production or sales volumes, worldwide supply and demand for oil and gas which affect their prices, competing supplies of gas in Australia, the timing and extent of our success in discovering, acquiring, developing and producing oil and natural gas reserves, risks inherent in the drilling and operation of oil and natural gas wells, future production and development costs, our ability to obtain financing for proposed activities, the effect of existing and future laws, governmental regulations and the political and economic climate of the United States and Australia, conditions in the capital markets, as well as our ability to obtain and continue gas sales contracts in Australia. For a discussion of these and other risks related to the forward-looking statements contained herein, please see "Risk Factors" as discussed in Items 1 and 2 of this Form 10-K.
OIL AND GAS RESERVES
At December 31, 2004, our total proved gas reserves were estimated to be 581 billion cubic feet ("Bcf"), of which 578 Bcf are attributed to our Comet Ridge Project in Queensland, Australia and 3 Bcf are attributed to domestic reserves located in our Frenchman and Republican projects. As of December 31, 2004, we had no oil reserves. Proved gas reserves, as defined by SEC regulation, are the estimated quantities of natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e. prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Accordingly, proved reserves do not reflect potentially higher prices under conditional contract provisions.
Using current market product prices in effect at such time and a discount rate of 10% as prescribed by SEC regulation, our total discounted future after-tax net cash flows were estimated to be $144.0 million as of December 31, 2004, compared to $107.6 million at December 31, 2003. The net increase in our discounted cash flows was due primarily to (i) extensions and discoveries at Comet Ridge and in Colorado and (ii) favorable changes in prices and production costs at our Comet Ridge project.
The present value of future net cash flows does not purport to be an estimate of the fair market value of our proved reserves. An estimate of the future value would also take into consideration, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money and the risks inherent in producing gas.
CRITICAL ACCOUNTING POLICIES
Our 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. We believe that the following are some of the more critical judgment areas in the application of our accounting policies that currently affect our financial condition and results of operations.
Oil and Gas Reserves
Estimated reserve quantities and estimated future development costs are used to calculate the rate at which we record depreciation, depletion and amortization (DD&A) expense. The process of estimating quantities of proved reserves is inherently uncertain, and the estimates of future net cash flows and their present values from our proved reserves are based upon various assumptions about future production levels and current prices and costs. Any significant variance from the assumptions could result in material differences in the actual quantity of our reserves and amount of estimated future net cash flows from the estimated oil and gas reserves. The discounted after-tax future net cash flows from the estimated reserve quantities impact the recorded value of our full cost pools as discussed below. If the estimate of proved reserve volumes declines or the estimate of future development costs increases, the DD&A expense we record increases, reducing net income. Certain early stage exploratory costs are excluded from costs subject to the DD&A calculation. We evaluate these excluded costs quarterly, and the costs are added to the DD&A base if we determine the costs will or will not result in commercially productive oil or gas production.
Full Cost Method of Accounting for Oil and Gas Properties
We account for our oil and gas properties using the full cost method. Under this method, we are required to record a permanent impairment provision if the net book value of our oil and gas properties (net of related deferred taxes) exceeds a ceiling value equal to the sum of (i) the present value of the future cash inflows from proved reserves, tax effected and discounted at 10% per annum, and (ii) the cost of unevaluated properties. The ceiling test is computed by country and at the end of each quarter. The oil and gas prices used in calculating future cash inflows in the United States are based upon the market price on the last day of the accounting period. Oil and gas prices are generally volatile; and if the market prices at a period end date have decreased, we may have to record an impairment. A loss may also be generated by the transfer of significant early stage exploratory costs to the oil and gas property cost pool that is subject to the ceiling test. These losses typically occur when significant costs are transferred to the oil and gas property cost pool as a result of an unsuccessful project without commercially productive oil and gas production.
The cost of our Australian properties is recorded in a separate full cost pool, as required under the full cost method. The prices received for sales in Australia, which are used to calculate future cash inflows are primarily based on short-term spot prices at the end of the accounting period and fixed prices received under existing long-term contracts. However, while there is less volatility with respect to the price received in Australian dollars, any volatility in the exchange rate affects the U.S. dollar equivalent price received and exposes us to a potential recorded loss in value.
In the event we record a reduction in our discounted after-tax future net cash flow from lower estimated reserve quantities, we could be required to record a non-cash loss. In addition, we could record a non-cash loss if costs associated with our domestic exploration projects are added to depletable costs within the domestic full cost pool without sufficient associated oil and gas reserves. While our oil and gas properties are subject to impairments based on product price declines, subsequent increases in value due to price increases will not be recorded. Subsequently, however, we would record a lower DD&A expense, since the prior impairment would have reduced the net book value of the full cost pool.
Contingencies
We account for contingencies in accordance with Statements of Financial Accounting Standards No. 5, "Accounting for Contingencies," which requires that we record an estimated loss from a loss contingency when information available prior to issuance of our financial statements indicates that it is probable that an asset has been impaired or a liability has been incurred at the date of the financial statements and the amount of the loss can be reasonably estimated. Accounting contingencies require us to use our judgment, and while we believe that our accruals for these matters are adequate, if the actual loss from the loss contingency is significantly different than the estimated loss, our results of operations of will be impacted in the period the contingency is resolved.
RECENT ACCOUNTING PRONOUNCEMENTS
See Note 1 to the Consolidated Financial Statements for recent accounting pronouncements and how we anticipate they will impact our financial statements.
LIQUIDITY AND CAPITAL RESOURCES
We have used equity and debt financings and sales of producing properties to fund most of our capital expenditures and operations during the last few years. These capital expenditures included the acquisition of additional interests in the Comet Ridge project in Queensland, Australia.
During 2004, we used $13.2 million of cash in operating activities and invested $15.9 million in capital expenditures and $5.0 million to purchase the registered titles in the Comet Ridge project in conjunction with the settlement of the Tri-Star litigation. See Note 12 to the Consolidated Financial Statements. Our operating activities and capital investments were funded with $26.6 million in net proceeds from debt financing and $8.3 million in proceeds from the sale of common stock.
Debt financing during 2004 consisted of approximately $17.7 million and $15.6 million received from Slough Trading Estates Limited ("STEL") and an Australian bank senior credit facility, respectively. These funds were primarily used for continued development of the Comet Ridge project and exploration of acreage within ATP 526. In addition, we borrowed $68.2 million from our senior credit facility to retire STEL debt of the same amount. See Note 2 to the Consolidated Financial Statements.
At December 31, 2004, we owed Slough Estates USA Inc. ("Slough") $4 million. The loan is due in April 2006 and bears an interest rate of LIBOR (2.306% as of December 31, 2004) plus 3.5%.
We have various commitments in addition to our long-term debt. The following table summarizes our contractual obligations at December 31, 2004 (in thousands):
(1)Senior credit facility based on financing institutions' latest repayment model (May 2004).
(2)Based on December 31, 2004 weighted average interest rate of 6.31% and anticipated debt repayment.
(3)Petroleum lease expenditures can be reduced or eliminated by governmental royalties paid on gas sales.
The table below provides an analysis of our capital expenditures of $20.9 million during the year 2004.
Capital Expenditures Activity in 2004
(in thousands)
Exploration and Development Drilling Commitments
Our anticipated capital expenditures during 2005 total approximately $28.5 million. In Australia, we expect to incur capital costs of $20 million of which $17 million would be for development drilling and for gas gathering and water disposal facilities and the remaining amount would be for exploration activities on ATP 653 and ATP 655. Capital spending in the United States, primarily on our Frenchman, Republican and Lay Creek projects, is expected to be approximately $8.5 million.
Of the $28.5 million described above, we plan to fund the $20 million estimated for the Australian capital expenditures using our Australian bank senior credit facility described below. Of the remaining $8.5 million in planned United States expenditures, we have determined approximately $6.0 million is discretionary and will be expended only if we obtain additional capital as described below.
We anticipate funding operations and capital expenditures in Australia and the United States for 2005 using (a) cash on hand at December 31, 2004, (b) net gas revenues, (c) expected proceeds of approximately $20 million ($25.7 million AUD) from long term borrowings under our $150 million AUD (approximately $117 million USD) Australian bank senior credit facility and (d) a commitment from Slough to provide funds for working capital, board-approved capital expenditures and operations 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. See Notes 2 and 4 to the Consolidated Financial Statements. At December 31, 2004, we have $25 million USD available for borrowings under our Australian credit facility. We anticipate having sufficient production history from our Frenchman and Republican project wells by late 2005 to be able to borrow money for further development of these projects. In order to fund discretionary domestic capital expenditures in 2005 in excess of these cash resources, we contemplate that we will require alternative sources of capital. Additional sources of funding may include additional debt financings and asset sales. Upon the sale of interests in our prospective acreage, we generally generate cash to reduce our investment in individual projects. 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.
In February 2005, the Company entered into an agreement with Houlihan Lokey Howard & Zukin Capital, Inc., an unrelated party, to provide financial advisory and investment banking services to the Company in connection with Slough's previously announced intention to divest of its ownership in the Company.
We anticipate funding operations and capital expenditures in Australia and the United States over the long-term using (a) net gas revenues, (b) domestic reserve-based debt financing and (c) other debt or equity instruments. We anticipate that our Australian gas sales will increase significantly by 2007, under existing long-term sales contracts, and will provide significant amounts of cash for Australian operating and capital expenditures along with servicing our debt. In the event sufficient long-term operating and capital funding cannot be obtained, we will be required to curtail planned expenditures and may have to sell additional acreage and/or relinquish acreage.
Year Ended December 31, 2003
During 2003, we used $6.6 million of cash in operating activities and invested $25.8 million in capital expenditures and $7.7 million in the repurchase of a royalty interest in the Comet Ridge project. We received proceeds of $3.2 million from the sale of oil and gas assets. Our operating activities and capital investments were funded with $38.5 million in net proceeds from debt financings.
Debt financing during 2003 consisted of approximately $68 million received from Slough Trading Estates Limited ("STEL"). This financing, as discussed in Note 2 to the Consolidated Financial Statements, was primarily used for continued development of the Comet Ridge project and exploration of acreage within ATP 526. In addition, the borrowing from STEL allowed us to retire TCW Asset Management Company ("TCW") debt of approximately $22 million, purchase the $7.7 million royalty interest held by TCW and repay $4.7 million in short term loans from Slough Estates USA Inc. ("Slough"). See Note 4 to the Consolidated Financial Statements. During 2003, we repaid with funds borrowed from STEL the $1.9 million debt associated with a drilling rig currently being used in Australia.
At December 31, 2003, we owed Slough Estates USA Inc. ("Slough") $4 million. The loan, which is due in April 2006, bears interest at LIBOR (1.178% as of December 31, 2003) plus 3.5%.
The table below provides a detailed analysis of our capital expenditures of $33.5 million during the year 2003.
Capital Expenditures Activity in 2003
(in thousands)
Included within 2003 capital spending was $699,000 of capitalized interest expense associated with our Australian and domestic properties.
During the year ended December 31, 2003, we received proceeds from asset sales of $3.2 million associated with the sale of a 75% interest in our Stateline prospect located in western Nebraska.
RESULTS OF OPERATIONS
Comparison of Year Ended December 31, 2004 and Year Ended December 31, 2003
We incurred a net loss of $15.3 million in 2004 compared to a net loss of $15.4 million in 2003. A $2.2 million increase in gas revenues was offset by increases in (i) legal expenses attributed to litigation, (ii) operating costs, and (iii) interest expense associated with increased debt used to fund our exploratory and development drilling programs in both Australia and the United States. The table below provides a comparison of operations. The table is intended to provide a comparative review of significant operational items and, 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.
(1)Average operating costs per Mcf for the year 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.
Revenues and Volumes
The 36% increase in our operating revenues was primarily attributed to a 14% increase in gas volumes sold and a 19% increase in average gas prices from our Australian Comet Ridge project. During the first half of 2004, all of our Australian Comet Ridge gas production was sold under a five-year contract with Energex
Retail Pty Ltd ("Energex"), an unaffiliated customer. During the last half of 2004, we sold our gas to four purchasers, including Energex, under various short and long term contracts. Favorable foreign currency exchange rates and increases to prices received under our gas contracts contributed to the average gas price increase.
We had nominal gas production and gas sales from our United States oil and gas properties.
In natural gas production operations, joint owners sometimes sell more or less than the production volumes to which they are entitled based on their revenue ownership interest. The joint operating agreement relating to the Comet Ridge project includes gas balancing provisions to govern production allocations in this situation. If excess takes of natural gas exceed our remaining proved reserves for the property, we record a natural gas imbalance in other liabilities. As of December 31, 2004, we had taken and sold more than our share of natural gas volumes produced from the Comet Ridge project, and we were overproduced by approximately 1,607 MMcf (net of royalties). Based on the December 31, 2004 average sales price of $1.88 per Mcf, this overproduction represents approximately $3.0 million in gas revenues. No liability has been recorded for the excess volumes taken as they did not exceed our share of remaining proved reserves. Under the terms of the gas balancing agreement, we may be required to reduce the monthly volumes we sell by up to 50% of our entitled share of sales, to enable underproduced parties to sell more than their entitled share of the gas sales and cure the imbalance.
Expenses
Australia operating expenses increased by 37% in 2004 primarily due to the increased production levels, workover expenditures, and transportation costs incurred to move gas to contract delivery points, and changes in foreign currency exchange rates. Average operating costs per Mcf sold in Australia increased from $0.88 per Mcf to $1.06 per Mcf, an increase of 20%. Operating costs averaged $1.36 per Mcf for the first half of 2004 due to lower sales volumes. A significant increase in sales volumes in the last half of 2004 increased our utilization of our compressor facilities, and reduced our average operating costs for the last half of 2004 to $0.92 per Mcf. In December 2003, we significantly increased our Comet Ridge compression capacity and associated costs in preparation for future sales increases.
Depletion expense for our Australian project increased 23% in 2004 primarily due to higher sales volumes and an increase of $0.02, or 6%, in the average depletion rate per unit produced and sold. Higher finding costs for reserves added was the principal factor increasing the depletion rate.
Domestic operating costs were largely attributable to the Lay Creek coalseam methane project where the initial wells are in the dewatering phase. Operating costs in the Powder River Basin, our sole domestic producing property in 2004 and 2003, averaged approximately $2.65 per Mcf, a decrease of 1% compared to the same period in 2003.
General and administrative expenses increased by $2.1 million or 37% in 2004 primarily due to legal and consulting costs for the Tri-Star litigation. We incurred $2.8 million in litigation related legal fees in 2004, an increase of approximately $1.4 million over 2003. With the Tri-Star litigation settlement closing in December 2004, we expect litigation legal fees and consulting expenses to decrease by more than $2 million in 2005.
Interest expense increased by approximately $2.3 million in 2004 primarily due to increased borrowings and higher loan balances. We were able to reduce the effective interest rate on the debt used to fund our Australian Comet Ridge project when we entered into a new bank senior credit facility which was used to refinance TOGA's debt owed to Slough and to fund development of the Comet Ridge project.
Income Taxes
We incurred net losses of $15.3 million, $15.4 million, and $4.8 million in 2004, 2003, and 2002, respectively. SFAS No. 109 "Accounting for Income Taxes" requires that a valuation allowance be provided
if it is more likely than not that some portion or all of a deferred tax asset will not be realized. Our ability to realize the benefit of our deferred tax asset will depend on the generation of future taxable income through profitable operations and the expansion of our exploration and development activities. The market and capital risks associated with achieving the above requirements are considerable, resulting in our conclusion that a full valuation allowance be provided. Accordingly, we did not recognize any income tax benefit in our Consolidated Statements of Operations for these years.
Comparison of Year Ended December 31, 2003 and Year Ended December 31, 2002
The Company incurred a net loss of $15.4 million in 2003 compared to a net loss of $4.8 million in 2002. The increase in the loss is principally attributable to the write-off of deferred loan costs, higher debt service costs, an impairment of the carrying value of the Company's U.S. oil and gas properties and higher operating costs. The increase in the higher operating costs was partially offset by a favorable currency exchange gain. The table below provides a comparison of operations. The table is intended to provide a comparative review of significant operational items and, 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.
(1)Average operating costs per Mcf for the year ended December 31, 2003 is for the Company's sole producing property in 2003. For a more meaningful comparison of operating costs per Mcf, significant operating costs associated with non-producing properties sold and properties in the dewatering stage have been excluded.
Revenues and Volumes
The 27% increase in our operating revenues was primarily due to increased gas production and higher gas prices received from our Australian Comet Ridge project. Australian revenues increased 38% due to a 15% increase in gas volumes sold and a 20% increase in average gas prices. Favorable foreign currency exchange rates were the principal factors contributing to the average gas price increase. Our Australian gas sales contracts in 2003 were long-term fixed contracts with yearly adjustments for inflation.
In natural gas production operations, joint owners sometimes sell more or less than the production volumes to which they are entitled based on their revenue ownership interest. The joint operating agreement relating to the Comet Ridge project includes gas balancing provisions to govern production allocations in this situation. If any excess takes of natural gas exceed its remaining proved reserves for the property, we record a natural gas imbalance in other liabilities. As of December 31, 2003, we had taken and sold more than our share of natural gas volumes produced from the Comet Ridge project, and we were overproduced by approximately 1,752 MMcf (net of royalties). Based on the December 31, 2003 average sales price of $1.78 per Mcf, this overproduction represents approximately $3.1 million in gas revenues. No liability was recorded for the excess volumes taken as they did not exceed our share of remaining proved reserves. Under the terms of the gas balancing agreement, we may be required to reduce the monthly volumes we sell by up to 50% of our entitled share of sales, to enable underproduced parties to sell more than their entitled share of the gas sales and cure the imbalance.
Domestic gas sales decreased significantly due to the sale of substantially all of our domestic producing properties in May 2002.
Expenses and Foreign Exchange Gains/Losses
Australia operating expenses increased by 41% in 2003 primarily due to an increase in the number of wells drilled and producing, an increase in the Company's ownership in the Comet Ridge project in mid-2002, and changes in foreign currency exchange rates. The average operating costs per Mcf sold in Australia increased from $0.72 per Mcf to $0.88 per Mcf, an increase of 22%. The rise in operating costs, principally in the Comet Ridge Fairview field, was due to higher field costs caused by the increase in the number of wells to be serviced and higher compressor costs.
Depletion expense for our Australian project increased 26% in 2003 primarily due to higher sales volumes and an increase in the average depletion rate per unit produced and sold. Higher finding costs for reserves added was the principal factor increasing the depletion rate.
The impairment expense of approximately $2.7 million was attributed largely to unsuccessful exploration on the Nine Mile prospect.
Domestic operating costs were largely attributable to the Lay Creek coalseam methane project where the initial ten wells were in the dewatering phase. Operating costs in the Powder River Basin, the Company's sole domestic producing property, averaged approximately $2.69 per Mcf.
General and administrative expenses increased 15% in 2003 primarily due to higher personnel costs associated with increased activity in Australia resulting from growth of the Comet Ridge project.
Interest expense increased by $2.9 million in 2003 due to increased borrowings and higher loan balances. In the third quarter of 2003, we wrote off approximately $5.1 million in deferred loan costs related to the TCW loan retired on August 15, 2003.
We recovered $924,000 of prepaid drilling costs previously written off in 2001 and 2000. Both the recovery and write-offs are associated with the litigation involving our Australian properties. See Note 12 to the accompanying Consolidated Financial Statements.
The foreign currency exchange gain, recognized in accordance with Statement of Financial Accounting Standard ("SFAS") No. 52, "Foreign Currency Translation" ("SFAS No. 52"), approximated $2.6 million in 2003. This gain was principally attributable to intercompany debt TOGA owed Tipperary Corporation prior to August 15, 2003. The non-permanent portion of this intercompany debt was substantially reduced on August 15, 2003.
ITEM 7A.
ITEM 7A. 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 and interest rates and commodity prices. We do not use financial instruments to any degree to manage foreign currency, interest rate and commodity risks and do not hold or issue financial instruments to any degree for trading purposes. At December 31, 2004, we were exposed to some market risk with respect to foreign currency, interest rates and natural gas prices; however, management does not believe such risk to be material.
Foreign Currency Risk
TOGA uses the Australian dollar as its functional currency. To the extent that business transactions in Australia are not denominated in the Australian dollar, we are exposed to foreign currency exchange risk. During 2003, we benefited from the non-permanent intercompany debt TOGA owed Tipperary Corporation that was denominated in U.S. dollars, and we recorded a foreign currency gain of $2.6 million related to this intercompany debt. As this non-permanent intercompany debt is now retired, we do not anticipate recording significant foreign currency gains or losses in 2005 due to changes in exchange rates. During 2004, our exchange gain was not significant. TOGA does expect to participate in some U.S. dollar transactions, but does not anticipate such transactions will result in a significant foreign currency risk. During 2003 and 2004, we experienced significant increases in our accumulated translation adjustment, the oil and gas properties accounts, and the standardized measure of proved reserve value due to the strengthening of the Australian dollar as compared to the U.S. dollar. We may experience significant changes in these accounts and the standardized measure during 2005 and in future years if exchange rates are volatile. The majority of our revenues, operating expenses and general and administrative expenses in Australia are incurred in Australian dollars. During 2003 and 2004, our revenues and expenses increased as a result of the strength of the Australian dollar. We expect our financial results will be impacted by exchange rate volatility, but we do not expect a significant effect on future earnings as a result of this volatility.
Interest Rate Risk
We currently have a significant amount of outstanding debt, and we are exposed to risk resulting from changes in interest rates. While a portion of our current debt is under long-term fixed interest rate agreements, our Australian debt facility has a floating rate. We are at risk that rates could increase and costs required to refinance the debt may be prohibitive. At current debt levels, a 1% change in interest rates will result in a cost or benefit to us of approximately $1.0 million per year.
Commodity Price Risk
Virtually all of our current sales revenues consist of natural gas sold in eastern Australia. The eastern Australian gas market is primarily composed of long-term fixed price contracts with adjustments made for the rate of inflation which minimizes our commodity price risk. Although not anticipated, we may be required to recognize a non-cash ceiling test impairment, as described in our Critical Accounting Polices found in Item 7 of this Form 10-K, of our Australian properties if more costs are added to the full cost pool than are supported by additional gas reserves or if the Australian dollar weakens significantly.
We have in the past and plan in the future to sell significant quantities of gas and oil in the United States market. If we do sell significant quantities of gas and oil in the United States, we may be exposed to price volatility that could affect our revenues and the carrying value of our U.S. oil and gas properties.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS
The Company's financial statements and related audit report appear on pages 29 through 61 in this annual report:
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Tipperary Corporation:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of stockholders' equity and of cash flows present fairly, in all material respects, the financial position of Tipperary Corporation and its subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 5 to the Consolidated Financial Statements, the Company changed its method of accounting for asset retirement costs effective January 1, 2003.
/s/ PricewaterhouseCoopers LLP
Denver, Colorado
March 23, 2005
TIPPERARY CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
($ in thousands except per share data)
See accompanying notes to Consolidated Financial Statements.
TIPPERARY CORPORATION AND SUBSIDIARIES
Consolidated Statements of Operations
(in thousands, except per share data)
See accompanying notes to Consolidated Financial Statements.
TIPPERARY CORPORATION AND SUBSIDIARIES
Consolidated Statement of Stockholders' Equity
(in thousands)
See accompanying notes to Consolidated Financial Statements.
TIPPERARY CORPORATION AND SUBSIDIARIES
Consolidated Statements of Cash Flows
(in thousands)
See accompanying notes to Consolidated Financial Statements.
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
NOTE 1-ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization
Tipperary Corporation and its subsidiaries (the "Company") are principally engaged in the exploration for and development and production of natural gas. The Company is primarily focused on coalseam gas properties, with its major producing property located in Queensland, Australia. The Company's activities in Australia are conducted through its 90%-owned Australian subsidiary, Tipperary Oil & Gas (Australia) Pty Ltd ("TOGA"). As of December 31, 2004, the Company owned a 75.25% undivided capital interest in the Comet Ridge project. The Company also holds exploration permits in Queensland and is involved in coalseam gas and conventional gas exploration in the United States through three projects in Colorado and two projects in Nebraska. The Company seeks to increase its reserves through exploration and development projects. The Company is a majority owned subsidiary of Slough Estates USA Inc. ("Slough"). At December 31, 2004, Slough held 54.5% of the Company's outstanding common stock.
Principles of Consolidation
The Consolidated Financial Statements include the accounts of Tipperary Corporation, its wholly-owned subsidiaries, Tipperary Oil & Gas Corporation, Tipperary CSG, Inc., Tipperary Queensland, Inc. and Burro Pipeline Corporation, and its 90%-owned subsidiary, TOGA. Slough owns the remaining 10% of TOGA. All intercompany transactions and balances have been eliminated in consolidation.
Liquidity and Operations
The Company has used equity and debt financings and sales of producing properties to fund most of its capital expenditures and operations during the last few years. These capital expenditures included the acquisition of additional interests in the Comet Ridge project in Queensland, Australia.
The Company anticipates capital expenditures during 2005 of approximately $28.5 million. In Australia, the Company expects to incur capital costs of $20 million, of which $17 million would be for development drilling and for gas gathering and water disposal facilities, and the remaining amount would be for exploration activities on ATP 653 and ATP 655. Capital spending in the United States, primarily on the Company's Frenchman, Republican and Lay Creek projects is expected to be approximately $8.5 million.
Of the $28.5 million described above, the $20 million estimated for the Australian capital expenditures is planned to be funded using the Company's Australian bank senior credit facility described below. Of the remaining $8.5 million in planned United States expenditures, the Company has determined approximately $6.0 million is discretionary and will be expended only if the Company obtains additional capital as described below.
The Company anticipates funding operations and capital expenditures in Australia and the United States for 2005 using (a) cash on hand at December 31, 2004, (b) net gas revenues, (c) approximately $20 million ($25.7 million AUD) in long term borrowings from the Australian senior credit facility and (d) a commitment from Slough to provide funds for working capital, board-approved capital expenditures and operations through April 2006. The Company's majority shareholder, 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. See Notes 2 and 4. At December 31, 2004 the Company had $25 million USD available for borrowings under its Australian credit facility. The Company anticipates having sufficient production history from its Frenchman and Republican project wells by late 2005 to be
able to borrow money for further development of these projects. In order to fund discretionary domestic capital expenditures in 2005 in excess of these cash resources, the Company contemplates that it will require alternative sources of capital. Additional sources of funding may include additional debt financings and asset sales. Upon the sale of interests in its prospective acreage, the Company generally generates 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.
Use of Estimates and Significant Risks
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in these financial statements and accompanying notes. The more significant areas requiring the use of estimates relate to the determination of proved oil and gas reserves and related future net cash flows and the unimpaired costs of unevaluated oil and gas properties. Actual results could differ from those estimates.
The Company is subject to a number of risks and uncertainties inherent in the oil and gas industry. Among these are risks related to fluctuating oil and gas prices, uncertainties related to the estimation of oil and gas reserves and the value of such reserves, effects of competition and extensive environmental regulation, risks associated with the search for and the development of oil and gas reserves, uncertainties related to foreign operations, and many other factors, many of which are beyond the Company's control. The Company's financial condition and results of operations depend significantly upon the prices received for natural gas. These prices are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond the control of the Company.
Cash and Cash Equivalents
The Company considers all highly liquid investments purchased with original maturities of three months or less to be cash equivalents.
Concentrations of Credit Risk
The Company maintains demand deposit accounts with two banks in Denver, Colorado and one bank in Brisbane, Queensland, Australia and invests cash in money market accounts which the Company believes have minimal risk of loss. In Australia during 2004, the Company had sales in excess of 10% of total Australian revenues to Energex Retail Pty Ltd of 82% and to Santos QNT Pty Ltd of 15%. During 2003 and 2002, the Company sold 100% and 97% of its gas production to Energex. The majority of the Company's receivables are within the oil and gas industry, primarily from the purchasers of its gas and its industry partners. The majority of receivables are not collateralized. To date, the Company has experienced minimal bad debts, and has no allowance for doubtful accounts at December 31, 2004 and 2003.
Financial Instruments
At December 31, 2004 and 2003, because the majority of the Company's long term debt bears interest at a variable rate, the fair value of its long-term debt approximates its carrying amount. The carrying amounts of cash and cash equivalents, receivables and accounts payable also approximated fair value because of the short maturity of these instruments at December 31, 2004 and 2003.
Derivative Instruments and Hedging Activities
The Company has not hedged oil and gas prices for any of its production since March 2000. The Company did not hedge its foreign currency exchange risk during 2004, 2003 or 2002. In the future the Company may
hedge gas prices on U.S. production and the Company may enter into derivative contracts to mitigate the risk of foreign currency exchange rate fluctuations.
Property, Plant and Equipment
The Company follows the full cost method to account for its oil and gas exploration and development activities. Under the full cost method, all costs incurred which are directly related to oil and gas exploration and development are capitalized and subjected to depreciation, depletion and amortization ("DD&A"). Costs related to production, general corporate overhead or similar activities are expensed as incurred. Depletable costs also include estimates of future development costs of proved reserves. Costs related to undeveloped oil and gas properties are excluded from depletable costs until such properties are evaluated as either proved or unproved. The net capitalized costs are subject to a ceiling limitation whereby a permanent impairment is recorded if the net book value of the Company's oil and gas properties (net of related deferred taxes) exceeds a ceiling value equal to the sum of (i) the present value of the future cash inflows from proved reserves, tax effected and discounted at 10% per annum, and (ii) the cost of unevaluated properties. The ceiling test is computed by country and at the end of each quarter. The oil and gas prices used in calculating future cash inflows in the United States are based upon the market price on the last day of the accounting period. Oil and gas prices are generally volatile, and if the market prices at a period end date have decreased, the Company may have to record an impairment. A loss may also be generated by the transfer of significant early stage exploratory costs to the oil and gas property cost pool that is subject to the ceiling test. These losses typically occur when significant costs are transferred to the oil and gas property cost pool as a result of an unsuccessful project without commercially productive oil and gas production. See Note 5. Gains or losses upon disposition of oil and gas properties are treated as adjustments to capitalized costs, unless such adjustment would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. Separate cost centers are maintained for each country in which the Company has operations. During 2004, 2003 and 2002, the Company's oil and gas operations were conducted in the United States and Australia.
Repairs and maintenance are expensed; renewals and betterments are capitalized. Certain indirect costs, including a portion of salaries, overhead and interest expense have been capitalized to the full cost pools.
Upon sale or retirement of property, plant and equipment other than oil and gas properties, the applicable costs and accumulated depreciation are removed from the accounts, and a gain or loss is recognized in the current period.
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. If excess takes of natural gas exceed its remaining proved reserves for the property it records a natural gas imbalance in other liabilities. As of December 31, 2004, 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 1,607 MMcf (net of royalties). Based on the December 31, 2004 average sales price of $1.88 per Mcf, this overproduction represents approximately $3.0 million in gas revenues. At December 31, 2004 and 2003 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 its entitled share of sales, to enable underproduced parties to sell more than their entitled share of the gas sales and cure the imbalance.
The Company receives rental income for the use of a drilling rig owned by TOGA and leased to a third party drilling contractor in Australia. See Note 6. The Company includes in revenue and expense rental income and depreciation expense when the rig is used to drill wells for other parties. Rig rental income and depreciation expense are capitalized to the Company's Australia full cost pool, rather than recorded as income and expense, when the rig is used to drill wells on the Company's properties.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization of oil and gas properties is provided using the units-of-production method computed using proved oil and gas reserves. Salvage value is taken into account in determining depletion rates.
Depreciation and amortization of other property and plant and equipment is provided using the straight-line method computed over estimated useful lives ranging from three to fifteen years.
Income Taxes
The Company accounts for income taxes under SFAS No. 109 which requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between the financial accounting and tax bases of assets and liabilities which will either be taxable or deductible when the assets or liabilities are recorded or settled. A valuation allowance is provided for deferred tax assets when management concludes it is more likely than not, that some portion of the deferred tax assets will not be realized.
Earnings (Loss) Per Share
Basic earnings (loss) per share is computed based on the weighted average number of shares outstanding. Diluted earnings (loss) per share is computed based on the weighted average number of common shares and the dilutive effect of unexercised stock options and warrants. Options and warrants to purchase 3.5 million, 3.6 million and 3.5 million shares of common stock at prices ranging from $1.50 to $5.13 per share were outstanding at December 31, 2004, 2003 and 2002, respectively, but were not included in the computation of diluted earnings per share because the effect would have been antidilutive. See Note 7.
Foreign Currency
Effective April 1, 2003, the Company changed the functional currency of its Australian subsidiary ("TOGA") from the U.S. dollar to the Australian dollar. In April 2003, TOGA began borrowing Australian dollars under its new debt agreement with Slough Trading Estates Limited ("STEL"), a UK company and wholly-owned subsidiary of Slough Estates plc and parent of Slough. See Note 2. That borrowing, combined with TOGA's assumption of operations of the Comet Ridge project and increased gas sales from the project, results in substantially all of TOGA's transactions being denominated in 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 at the balance sheet date, 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 and is accumulated and reported as a separate line item in stockholders' equity in the Company's Consolidated Financial Statements.
The cumulative foreign currency translation adjustment as of December 31, 2004 and 2003 totaled $7.8 million and $7.1 million (net of $-0- tax due to the Company's net operating loss carryforwards). In accordance with SFAS No. 52, during the year ended December 31, 2003, the Company recognized a foreign currency exchange gain of $2.6 million, related to intercompany debt. Substantially all of this foreign exchange gain relates to intercompany debt TOGA owed Tipperary Corporation prior to
August 15, 2003. The non-permanent portion of intercompany debt was substantially reduced on August 15, 2003. See Note 2.
Stock-Based Compensation
SFAS No. 148, "Accounting For Stock-Based Compensation-Transition and Disclosure," ("SFAS No. 148") and SFAS No. 123, "Accounting For Stock-Based Compensation," ("SFAS No. 123") encourage, but do not require, companies to record the compensation cost for stock-based employee compensation plans at fair value. At December 31, 2004, the Company had two stock-based employee option plans and warrants issued to directors and employees. See Note 9. 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 No. 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 adopted the cost recognition provisions of SFAS No. 123 are presented below.
The Company has also granted warrants to non-employees for services rendered. These warrants are recorded at fair value in accordance with SFAS No. 123. See Note 9.
Financing Costs
Costs incurred to obtain financing through the issuance of stock are accounted for as a reduction of the related proceeds. Costs attributable to raising debt financing, including the present value of future royalty payments, are capitalized and amortized using the effective interest rate method.
Minority Interest
Slough's 10% ownership in TOGA has been accounted for as a minority interest in the accompanying Consolidated Financial Statements. In 2004, the 10% minority interest share of TOGA's net loss totaled approximately $1.2 million. The minority interest in TOGA's net equity at January 1, 2004 totaled $418,000, which was fully offset due to losses incurred for the year end December 31, 2004. 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.
Significant Customers
In the United States, the Company has sold its oil and gas production to several purchasers during the past several years, generally under short-term contracts. During 2004 and 2003, the Company did not have material domestic oil or gas sales. In 2002, the Company had domestic sales in excess of 10% of total U.S. revenues to BP America Production Co. and Smith Production Inc. of 54% and 40%, respectively.
In Australia during 2004, the Company had sales in excess of 10% of total Australian revenues to Energex Retail Pty Ltd of 82% and to Santos QNT Pty Ltd of 15%. During 2003 and 2002, the Company sold 100% and 97% to Energex. As of December 31, 2004, the Company's Australia natural gas sales are made to four purchasers under various short and long-term contracts. Loss of revenue from any of the Company's gas customers for any reason, including nonpayment, reduction in sales or lost gas supply contracts could have a negative impact on the Company's results of operation, financial condition or cash flows.
Segment Information
The Company has two geographic reporting segments within the oil and gas exploration, development and production industry. The Company operates in two geographic areas, the United States and Australia. See Notes 13 and 14.
Issuance of Subsidiary Common Stock
Sales of stock by a subsidiary are accounted for as capital transactions. No gain or loss is recognized on these transactions. During 2004, 2003 and 2002, no subsidiary stock was issued.
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 Company expects to adopt SFAS No. 123R effective July 1, 2005 using the modified prospective application with no restatement of prior interim periods. The Company does not expect SFAS No. 123R to have a material effect on the Company's Consolidated Financial Statements.
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity" ("SFAS No. 150"). SFAS No. 150 establishes standards on the classification and measurement of certain financial instruments with characteristics of both liabilities and equity. The provisions of SFAS No. 150 are effective for financial instruments entered into or modified after May 31, 2003, and generally to all other instruments that exist as of the beginning of the first interim financial reporting period beginning after June 15, 2003. The adoption of SFAS No. 150 did not have a material effect on the Company's Consolidated Financial Statements.
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities" ("FIN 46") which requires the consolidation of variable interest entities, as defined. In December 2003, the FASB issued Interpretation No. 46R, "Consolidation of Variable Interest Entities-An Interpretation of ARB 51 (Revised December 2003)" ("FIN 46R"), which amended FIN 46. The adoption of FIN 46R effective January 1, 2004 did not have a material effect on the Company's Consolidated Financial Statements.
NOTE 2-RELATED PARTY TRANSACTIONS
At December 31, 2004, the Company owed Slough and STEL approximately $17.0 million. See Note 8.
In December 2003, Slough Estates plc, STEL's parent, guaranteed through June 9, 2009, the recourse portion of a senior credit facility of $150.0 million AUD that closed in June 2004. As consideration for the guarantee, the Company pays 1% per annum on the daily outstanding balance of the recourse debt guaranteed which was approximately $91.4 million at December 31, 2004. During 2004, the Company paid guarantee fees of $425,000.
On August 15, 2003, TOGA borrowed $29.7 million ($45 million AUD) from STEL for the sole purpose of paying off the $22 million long-term debt owed TCW Asset Management Company ("TCW") and to substantially fund the $7.7 million repurchase of the 6% overriding royalty held by TCW on the Company's Comet Ridge properties. As a result of retiring the TCW debt, TOGA's intercompany debt with the Company was reduced by approximately $22 million. In addition, TOGA borrowed $55.0 million AUD under a credit facility agreement with STEL to fund its operations in Australia. These loans bore interest at 13% per annum. In connection with these loans, the Company paid arrangement fees of $250,000 USD and $100,000 AUD (approximately $75,000 USD), respectively to STEL. These loans were paid off in full on June 18, 2004 with funds from an Australian bank senior credit facility. See Note 4.
In March 2003, the Company entered into a credit facility agreement with STEL allowing the Company to borrow on an unsecured basis up to $8.5 million USD. On September 3, 2004, the borrowing limit of this facility was amended to $13 million USD. Using borrowings from this credit facility, the Company substantially funded its operating and capital needs in the United States in 2004. This loan bears interest at 13% per annum. The Company may repay the loan in whole or in part without prepayment penalties. STEL may demand repayment prior to the maturity date of April 2, 2012 provided that STEL gives 18-month notice. The Company is limited in taking on any additional third party indebtedness, either secured or unsecured, or conferring 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 USD. The U.S. dollar value of the outstanding balance of this facility as of December 31, 2004 and 2003 was $13 million and $9 million, respectively.
In 2002, the Company borrowed $4 million from Slough which is evidenced by a note payable that bears interest at LIBOR plus 3.5% (5.806% as of December 31, 2004) and is payable in full on April 30, 2006.
In January 2001, Slough advanced the Company $2.5 million to finance the purchase of a drilling rig used in Australia. During 2003, the Company paid in full the outstanding balance as of December 31, 2002 of approximately $1.9 million.
During 2004 and 2003, the Company paid interest on the above loans to Slough of approximately $198,000 and $366,000, respectively and to STEL of approximately $5.5 million and $3.5 million, respectively. During 2002, the Company paid Slough interest of approximately $273,000.
Slough has committed to provide funds to the Company with long-term loans or equity contributions through April 2006 to be used for working capital, board-approved capital expenditures and operations.
NOTE 3-OIL AND GAS PROPERTY SALES
In July and October 2003, the Company sold to an unaffiliated third party, a 75% interest in the Stateline prospect in western Nebraska for $3.2 million in cash. The Company retained a 25% interest in the acreage. Total gross acreage sold in the project was approximately 117,000 acres. The purchaser serves as operator of the project. In accordance with the full cost accounting rules, the Company recorded the proceeds as a reduction of its domestic full cost pool, with no gain being recognized.
On November 27, 2002, the Company sold to Kerr-McGee Rocky Mountain Corporation ("Kerr-McGee"), an unaffiliated third party, interests ranging from 75% to 80% in the Frenchman and Republican prospects in eastern Colorado for $4.8 million. The Company retained the remaining 25% to 20% interests in the acreage. As a result of the initial sale, the Company recorded a $1.4 million gain. The
Company entered into a joint operating agreement with Kerr-McGee designating Kerr-McGee as operator. Since then Kerr-McGee has sold all of its ownership interest in these properties to The Houston Exploration Company.
On May 24, 2002, the Company sold all of its undivided interests in the West Buna field in Jasper and Hardin counties, Texas to Delta Petroleum Corporation ("Delta"), an unaffiliated third party, for $4.1 million in cash. The Company recognized a gain of $766,000 on the sale.
NOTE 4-COMET RIDGE PROJECT FINANCING AND ACQUISITIONS
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. See Note 2. 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 (6.33% per annum as of December 31, 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 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 December 31, 2004, the Company's covenant obligations relate primarily to reporting requirements. At December 31, 2004 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 December 31, 2004 was approximately $91.4 million ($117.3 million AUD), including interest due which will be paid with funds borrowed from the facility of $379,000 ($486,000 AUD). TOGA incurred $4.1 million in loan costs, which TOGA has deferred and is amortizing over five years. During 2004, TOGA paid interest and commitment fees of approximately $2.5 million and $80,000, respectively on this facility.
Through August 15, 2003, the Company was a party to an amended and restated credit agreement with TCW with a principal balance of $22 million, which was used for development of the Comet Ridge project. This credit agreement was paid in full with proceeds from a financing arrangement entered into with STEL. See Note 2. On August 15, 2003, the Company used proceeds from a STEL financing to acquire a 6% overriding royalty interest held by TCW on the Comet Ridge properties.
In connection with the TCW credit agreement, the Company recorded in 2001 debt issuance costs of approximately $6.8 million which was the then present value (discounted at 15%) of the overriding royalty conveyed to TCW. This cost reduced the book value of the Company's oil and gas properties in Australia and was being amortized as interest expense over the life of the loan. Debt issuance costs also include approximately $1.7 million of other costs incurred to obtain the TCW financing, which were likewise being amortized as interest expense over the life of the loan. The remaining unamortized debt issuance costs of $5.1 million were expensed in full in the third quarter of 2003 with the retirement of the TCW debt.
On May 24, 2002, the Company acquired for $5.55 million a 5% interest in the Comet Ridge project from Delta and an option to purchase Delta's interests of 2.5% or less in each of six other Authority to Prospect areas that have no proved reserves. The option to purchase Delta's interests in six other Authority to Prospect areas expired during 2003. The purchase price included $4.8 million in cash, $300,000 in assumed obligations, and 250,000 unregistered shares of the Company's common stock valued at $450,000. This acquisition increased the Company's total capital-bearing interest in the Comet Ridge project from 65% to 70%.
On June 3, 2002, the Company acquired from other non-affiliated private parties four separate interests in the Comet Ridge project, for approximately $2.3 million in cash, which increased the Company's total capital-bearing interest in the Comet Ridge project from 70% to 73%.
In December 2004, pursuant to a settlement agreement reached with Tri-Star Petroleum Company ("Tri-Star"), the Company paid Tri-Star consideration of $5.0 million for 96% of each of the registered titles for the Comet Ridge project previously held in Tri-Star's name, including, but not limited to, the relevant Authorities to Prospect and Petroleum Leases and for Tri-Star's 2.25% working interest in the Comet Ridge project, subject to a 1.5% contractual overriding royalty interest to be retained by Tri-Star out of the conveyed interest. See Note 12. The Company performed a formal valuation of the working interest, overriding royalty interest and registered titles and as a result of that valuation capitalized the $5.0 million payment to Tri-Star as an addition to its Australian full cost pool. This acquisition increased the Company's total capital-bearing interest in the Comet Ridge project from 73% to 75.25%.
NOTE 5-OIL AND GAS FULL COST POOLS
Under the full cost method of accounting, capitalized oil and gas property costs, net of accumulated DD&A and related deferred income taxes, may not exceed a "ceiling" value comprised of the total of the present value of future net revenues from proved reserves, discounted at 10% per annum, plus the cost of unevaluated properties excluded from costs being amortized, net of related income tax effects. This "ceiling test" is performed quarterly on a country-by-country basis.
Australia
The Company's Australia full cost pool includes acquisition, drilling and completion costs, seismic costs, and costs to construct gas gathering lines. The Company holds an interest in the Comet Ridge project and has acquired and begun exploration activities on its own Authorities to Prospect (ATPs) in Queensland. As of December 31, 2004, the net book value of the Australia full cost pool was approximately $127.5 million. During 2004, 2003 and 2002, the ceiling value exceeded the net capitalized costs in the Australia full cost pool.
United States
The Company's domestic full cost pool includes capital costs incurred in domestic property acquisition, exploration and development. The net book value of the United States full cost pool as of December 31, 2004 was $10.5 million. At December 31, 2004, the ceiling value exceeded the net capitalized costs in the United States full cost pool. At March 31, 2004, the Company recorded a $150,000 ceiling test impairment on the Frenchman project. In 2003, the Company recognized a ceiling test impairment of $2.7 million attributed largely to unsuccessful exploration on the Nine Mile prospect.
Unproved property costs
Costs, including related capitalized interest expense, attributable to unproved oil and gas leases and exploration costs that have been excluded from depletable costs pending further evaluation as of December 31, 2004 are as follows (in thousands):
Costs excluded from capitalized costs being amortized are periodically assessed for possible impairment or reduction in value. If a determination is made that a reduction in the value of a property has occurred, the reduction is included in costs to be amortized or charged against earnings where a reserve base had not yet been established in the full cost pool. Exploration costs are transferred to the amortizable base upon completion of evaluation.
Asset Retirement Obligations
In June 2001, the FASB issued SFAS 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 Company adopted SFAS No. 143 on January 1, 2003, which resulted in an increase in property, plant and equipment of $134,000 and establishment of an asset retirement obligation of $180,000. The balance of $46,000 was recorded as a transition adjustment and reported as a cumulative effect of accounting change (net of $-0- tax) in the Company's Consolidated Statement of Operations for the year ended December 31, 2003. If the Company had applied the provisions of SFAS No. 143 on January 1, 2002, the Company's asset retirement obligation would have been $145,000. There was no pro forma impact on earnings per share from the adoption of SFAS No. 143. Assuming SFAS No. 143 had been adopted on January 1, 2002, the Company's pro forma net loss would have been $4.83 million for the year ended December 31, 2002.
The Company's reconciliation of its asset retirement obligation is shown below.
NOTE 6-OTHER PROPERTY AND EQUIPMENT
In 2001, TOGA acquired a drilling rig ("Soilmec rig") and related equipment from the manufacturer for a total cost of approximately $2.7 million using a loan from Slough. TOGA acquired the Soilmec rig for lease to Mitchell Drilling Contractors Pty. Ltd. ("Mitchell"), an unaffiliated third party, to drill wells on the Comet Ridge project under a turnkey drilling contract that would provide for accelerated drilling at a reduced cost. TOGA leased the drilling rig to Mitchell under the terms of an agreement that provides that Mitchell use the rig to drill on the Comet Ridge project and TOGA's other ATPs. To the extent the rig is not being used for TOGA's drilling activities, it may, with TOGA's consent, be used by Mitchell to drill wells for other parties. The lease payments are structured to be due and payable with the drilling of each well. No interest or finance charges accrue on the lease, but the Company benefits from reduced costs to drill each well on the Comet Ridge project or its other ATPs. In the case of drilling on the Comet Ridge project, the Company's co-owners also benefit from their proportionate share of any cost reductions. In 2001, Mitchell also received a two-year option to buy the rig and related equipment at TOGA's net cost
remaining after lease payments. In 2002, this option to buy was extended until the earlier of April 2006 or the drilling of 48 wells on the Comet Ridge project using the Soilmec rig owned by TOGA and a second Soilmec rig owned by Mitchell.
During 2004, the rig was used to drill or complete seven wells at Comet Ridge and four wells for a third party. The Company received rental income during 2004 totaling $425,000. During 2003, the rig was used to drill or complete 17 wells at Comet Ridge, and the Company received rental income totaling $680,000. During 2002, the rig was used to drill or complete 12 wells at Comet Ridge and two wells for a third party. All rental income received from Mitchell was used for principal payments on the associated Slough loan. As of December 31, 2004, the Soilmec rig has been used to drill 37 wells on the Comet Ridge project. The Company expects the Soilmec rig will continue to be used to drill wells on Comet Ridge acreage during 2005. See "Revenue Recognition and Gas Imbalances" under Note 1 for a discussion of how rig rental income and depreciation expense are reflected in the Company's consolidated financial statements.
In December 2003, the Company paid in full the outstanding balance on the loan from Slough used to acquire the Soilmec rig. During 2003, the Company paid a total of $1.91 million in principal payments on the Soilmec rig loan.
NOTE 7-LOSS PER SHARE
The following table sets forth the computation of basic and diluted earnings (loss) per share (in thousands except per share data):
NOTE 8-LONG-TERM DEBT
Long-term notes payable (in thousands), their interest rates per annum and maturity dates are summarized below:
See Note 12 for five year schedule of debt payments.
NOTE 9-STOCKHOLDERS' EQUITY
Preferred Stock
The Company's preferred stock may be divided into and issued in series. With respect to each series, the Board of Directors is authorized to establish dividend rates, price, terms and conditions of redemption, liquidation terms, sinking fund requirements, conversion rights and voting rights.
Common Stock Issuances
On September 23, 2004, the Company sold two million unregistered shares of its common stock at a price of $4.00 per share to 11 unaffiliated institutional investors, resulting in net proceeds of approximately $7.9 million. These shares were registered effective January 17, 2005.
In May 2002, the Company issued unregistered common stock to Delta in the acquisition of Delta's 5% interest in the Comet Ridge project. The purchase price included $4.8 million in cash, $300,000 in assumed obligations, and 250,000 unregistered shares of the Company's stock valued at $450,000.
Warrants
At December 31, 2004, the Company had outstanding approximately 3.2 million warrants to purchase shares of the Company's common stock. The Company's major shareholder, Slough, holds 1.7 million warrants of which 500,000 warrants with an exercise price of $3.00 per share expire in December 2005 and 1.2 million warrants with an exercise price of $2.00 per share expire in December 2009. Approximately 288,000 warrants were issued to other investors. The Company's employees and directors and non-employee consultants hold approximately 1.2 million warrants.
Stock Based Compensation Plan
The 1987 Employee Stock Option Plan (the "1987 Plan") provided for option grants for a maximum of 383,000 shares. The 1987 Plan expired December 31, 1996. The 121,000 options outstanding as of December 31, 2004 under this plan have a term of ten years ending no later than October 2006, an exercise price equal to the fair market value of the stock on the date of grant and qualify as incentive stock options as defined in the Internal Revenue Code of 1986 ("the Code").
The 1997 Long-Term Incentive Plan (the "1997 Plan") was adopted to replace the expired 1987 Plan. The 1997 Plan was amended in January 2000 to increase the shares of common stock issuable from 250,000 to 500,000 for a period expiring in 2007. The 163,000 options outstanding as of December 31, 2004 have a term of ten years and an exercise price equal to the fair market value of the stock on the date of grant. The 1997 Plan provides that participants may be granted awards in the form of incentive stock options, non-qualified options as defined in the Code, stock appreciation rights, performance awards related to the Company's operations, or restricted stock. At December 31, 2004, a total of 293,500 shares were available for future grant.
Options Granted to Employees
In 2003 and 2002, the Company granted to employees stock options that have contractual terms of 10 years and an exercise price equal to the fair market value of the stock at grant date. The options granted vest one-third each year, beginning on the first anniversary of the date of grant. A summary of the status of the
Company's stock options granted to employees as of December 31, 2004, 2003 and 2002 and the changes during the periods ended on those dates are presented below:
The fair value of each stock option granted is estimated as of the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions:
(1)No options were granted to employees in 2004. The following table summarizes information about employee stock options outstanding at December 31, 2004:
Warrants Issued to Employees and Directors
In 2003 and 2002, the Company granted to employees warrants with an exercise price equal to the fair market value of the stock at grant date. The warrants granted vest one-third each year, beginning on the first anniversary of the date of grant.
A summary of the status of the Company's warrants granted to employees and directors as of December 31, 2004, 2003 and 2002 and the changes during the periods ended on those dates are presented below:
The fair value of each of the warrants granted to employees and directors is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions:
(1)No warrants were granted to employees or directors in 2004. The following table summarizes information about employee and director warrants outstanding at December 31, 2004:
Non-Employee Compensatory Warrants
A summary of the status of the Company's warrants granted to non-employees as of December 31, 2004, 2003 and 2002 and the changes during the periods ended on those dates are presented below:
The fair value of each of the warrants granted to non-employees is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions:
(1)No warrants were granted to non-employees in 2003. An expense equal to the Black-Scholes option-pricing model fair value of the warrants is recorded over the vesting period.
The following table summarizes information about non-employee warrants outstanding at December 31, 2004:
NOTE 10-STATEMENT OF CASH FLOWS SUPPLEMENTAL INFORMATION
NOTE 11-INCOME TAXES
Deferred income tax assets and liabilities are comprised of the following (in thousands):
Income tax expense (benefit) is different than the expected amount computed using the applicable federal statutory income tax rate of 35%. With the Australian statutory income tax rate at the lower 30%, no
additional income tax expense would result from foreign operations. The reasons for and effects of such differences (in thousands) are as follows:
At December 31, 2004, the Company had U.S. net operating loss carryforwards of approximately $85 million to apply against future taxable income and $83 million to apply against future alternative minimum taxable income. The losses expire within 15-20 years after the date incurred, with approximately $2.5 million expiring by 2010, approximately another $4.5 million by 2012, and the remainder expiring in the years 2018 through 2024. Additionally, the Company has Australian net operating loss carryforwards of approximately $45 million USD which can be carried forward indefinitely
The Company also has statutory depletion carryforwards and minimum tax credit carryforwards which do not expire. The Company's U.S. net operating loss carryforwards would be subject to an annual limitation should there be a change of over 50% in the stock ownership of the Company during any three-year period. As of December 31, 2004, no such ownership change had occurred. The sale of Slough's majority interest would constitute such a change. If an ownership change had occurred as of December 31, 2004, the net operating loss carryforwards would be subject to an annual limitation of approximately $7.0 million.
The Company does not expect to pay income taxes in the near term. In the United States, the utilization of net operating loss carryforwards ($85 million) will reduce the Company's effective federal tax rate from approximately 35% to approximately 2% in years the Company generates taxable income. The Company has recorded an asset for the future benefit of its United States and Australian carryforwards and other tax benefits. As of December 31, 2004 and 2003, this asset was completely offset by a valuation allowance based upon management's projection of its realizability. Fluctuations in the Company's performance, industry conditions and trends will require periodic management reviews of the recorded valuation allowance to determine if a decrease in the allowance is appropriate. A decrease in the allowance would result in an income tax benefit and a subsequent increase in the valuation allowance would decrease net income. The Company has not generated taxable income in Australia and with its loss carryforwards does not expect to generate taxable income in Australia in the near term.
NOTE 12-COMMITMENTS AND CONTINGENCIES
Until December of 2004, the Company, TOGA and two unaffiliated working interest owners were 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 alleged, among other matters, that Tri-Star and/or the individual defendants failed to operate the project in a good and
workmanlike manner and committed various other breaches of a joint operating contract, breached a previous mediation agreement, committed certain breaches of fiduciary and other duties owed to the plaintiffs, and committed fraud in connection with the project. Tri-Star answered the allegations, and filed amended pleadings denying liability and raising a number of affirmative defenses and asserting various counterclaims. TOGA operated the project beginning in March 2002, after the court entered a 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.
On October 30, 2004, the Company and Tri-Star entered into a settlement agreement covering this litigation, as well as all other litigation between those parties originating in Queensland, Australia. Pursuant to the settlement agreement the Company will continue as operator, and Tri-Star has transferred to the Company 96% and two unrelated intervening plaintiffs the remaining 4% of each of the registered titles for the Comet Ridge project held in its name, including, but not limited to, the relevant Authorities to Prospect and Petroleum Leases. Tri-Star has transferred to a newly-formed subsidiary of Tipperary Corporation, Tipperary Queensland, Inc., a 2.25% working interest in the Comet Ridge project, subject to a contractual overriding royalty interest that approximates 2.5% of Tipperary's future Comet Ridge revenues (net of pipeline tariffs) and is equivalent to 1.5% of all Comet Ridge gas produced and sold. The transfer of the registered titles has been completed. Under the settlement agreement the Company has paid $5.0 million to Tri-Star, using existing cash and TOGA's Australian loan facility. In addition to other provisions, the settlement agreement provides that all claims made by the Company, Tri-Star and the individual defendants are to be dismissed without ability to refile. The order actually dismissing the claims was signed on December 15, 2004. The Company, the individual defendants and Tri-Star have each released each other from liability for any claims that were or could have asserted in the litigation, whether known or unknown.
Other Commitments and Contingencies
The Company has various commitments in addition to its long-term debt. During the years ended December 31, 2002, 2003 and 2004, total operating lease expense for office space and equipment was $1.0 million, $1.6 million and $1.9 million, respectively. The following table summarizes the Company's contractual obligations at December 31, 2004 (in thousands):
(1)Senior credit facility based on financing institutions' latest repayment model (May 2004).
(2)Based on December 31, 2004 weighted average interest rate of 6.31% and anticipated debt repayment.
(3)Petroleum lease expenditures can be reduced or eliminated by governmental royalties paid on gas sales.
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 in 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 using directional drilling from drill sites adjacent to park lands. Directional drilling is used to produce some coalseam and conventional gas in the U.S. Management believes directional drilling can be
used effectively at Comet Ridge in lieu of drilling from inside the parks. Management does not expect these new requirements to significantly increase future exploration, development and operating costs per mcf sold. Three of the Company's productive wells and one ATP 526 exploration well were previously permitted on park lands. Under current government policy, the four wells 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 reserves 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 13-OPERATIONS BY GEOGRAPHIC AREA
Segment information has been prepared in accordance with Statements of Financial Accounting Standards No. 131, "Disclosures About Segments of an Enterprise and Related Information." The Company has two geographic reporting segments within the oil and gas exploration, development and production segment. Corporate expenses are not allocated to the geographic segments. The segment data presented below was prepared on the same basis as the Consolidated Financial Statements.
Year ended December 31, 2004
Year ended December 31, 2003
Year ended December 31, 2002
NOTE 14-SUPPLEMENTARY INFORMATION ON OIL AND GAS OPERATIONS
Certain historical cost and operating information relating to the Company's oil and gas producing activities are as follows (in thousands):
CAPITALIZED COSTS
(1)Costs to develop proved undeveloped reserves during 2003 and 2002 were $4.5 million and $6.8 million. No proved undeveloped reserves were developed in 2004.
(2)Includes $1.0 million in costs reimbursed by Koch Exploration Company.
The rates of depletion per Mcf of sales in the United States were nil in 2004, nil for 2003 and $1.11 for 2002. Excluded from depletable costs are costs of $8.5 million in 2004, $6.2 million in 2003 and $6.3 million in 2002 related to United States properties that have not yet been evaluated.
The rates of depletion per Mcf of sales in Australia were $0.34 in 2004, $0.32 for 2003 and $0.29 for 2002. Excluded from depletable costs are costs of $11.5 million in 2004, $9.2 million in 2003 and $3.6 million in 2002 related to Australian properties that have not yet been evaluated.
RESULTS OF OPERATIONS
The results of operations for petroleum producing activities are reflected in Note 13, Reportable Segments.
ESTIMATES OF PROVED OIL AND GAS RESERVES (UNAUDITED)
The following table presents the Company's estimates of its proved oil and gas reserves. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of mature producing oil and gas properties. Accordingly, the estimates are expected to change as future information becomes available. Reserve estimates are prepared by independent petroleum engineers Data Consulting Services, a division of Schlumberger Technology Corporation.
(1)Ten percent of the proved and proved developed reserves are attributable to the minority interest held by Slough in TOGA.
(2)Tri-Star's 2.25% working interest in the Comet Ridge project received under the October 30, 2004 Settlement Agreement.
(3)Represents an overriding royalty retained by Tri-Star under the Settlement Agreement.
(4)Relates to 6% royalty conveyed to Trust Company of the West in 2001 and repurchased in 2003. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)
The following standardized measure of discounted future cash flows was prepared in accordance to the guidelines stipulated by SFAS No. 69, "Disclosures about Oil and Gas Producing Activities", (SFAS No. 69) summarized below.
Future cash inflows and future production and development costs have been estimated using prices and costs in effect at the end of the years indicated, except in those instances where the sale of gas is covered by contracts, in which case, the applicable contract prices were used for the duration of the contract. Accordingly, price escalations based upon future conditions or potentially higher prices under conditional contract provisions were not considered. Estimated future income taxes are computed using current statutory income tax rates for both the U.S. and Australia including consideration for the tax bases of properties and related carryforwards, giving effect to permanent differences and tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor. Estimates for future general and administrative and interest expense have not been considered.
Changes in inflation, the demand for gas, foreign exchange rates and other factors make such estimates inherently imprecise and subject to substantial revision. The assumptions used to compute the
standardized measure are those prescribed by SFAS No. 69 and, as such, do not necessarily reflect the Company's expectations of actual revenue to be derived from those reserves nor the present worth.
(1)Ten percent of the discounted future net cash flows are attributable to the minority interest held by Slough in TOGA.
(2)Income tax expense is computed using the Company's overall effective tax rate for each respective year and takes into consideration the Company's net operating loss carryforwards and the tax bases of the oil and gas properties.
Principal changes in the Company's estimated discounted future net cash flows (in thousands) are as follows:
At December 31, 2004 the period end gas price used in the determination of future cash flows for Australia and United States reserves was $1.87 and $5.56 per Mcf, respectively.
(1)Includes effect for changes in timing of production.
(2)Represents an overriding royalty retained by Tri-Star under the October 30, 2004 Settlement Agreement.
(3)Tri-Star's 2.25% working interest in the Comet Ridge project received under the Settlement Agreement.
At December 31, 2003, the average gas contractual price used in the determination of future cash flows for Australia reserves was $1.78 per Mcf.
(1)Includes effect for changes in timing of production
At December 31, 2002, period-end oil and gas prices used in the determination of future cash flows for United States reserves were $30.25 per barrel and $3.58 per Mcf, respectively. The average gas contractual price used in the determination of future cash flows for Australia reserves was $1.31 per Mcf.
(1)Includes effect for changes in timing of production. NOTE 15-QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
The following is a summary of the unaudited quarterly results of operations (in thousands, except per share data):
(1)Includes revenue less operating expense and excludes DD&A.
(2)The quarter ended June 30, 2003 included a $2.2 million write-down of domestic oil and gas properties and a $3.1 million foreign currency gain.
(3)The quarter ended September 30, 2003 included a write-off of deferred loan costs of $5.1 million and a $165,000 write-down of domestic oil and gas properties.
(4)In the quarter ended December 31, 2003, the Company recovered $924,000 of a 2001 write-down of prepaid drilling advances and recorded a $293,000 write-down of domestic oil and gas properties.
(5)The quarters ended June 30 and December 31, 2002 included gains on sale of assets of $766,000 and $1.4 million, respectively.
(6)In the quarter ended September 30, 2002, the Company recovered $282,000 of a 2001 write-down of prepaid drilling advances. NOTE 16-SUBSEQUENT EVENT
On February 22, 2005, the Company entered into an agreement with Houlihan Lokey Howard & Zukin Capital, Inc. ("Houlihan Lokey"), an unrelated party. Houlihan Lokey will provide financial advisory and investment banking services to the Company in connection with Slough's previously announced intention to divest of its ownership and investments in the Company. For these services Houlihan Lokey will receive from the Company a monthly retainer fee of $100,000 for the first two months of service and $50,000 thereafter, and will receive from the Company a cash fee of 4% of the transaction value upon consummation of a financing or sale transaction whereby Slough divests its interests, and will be reimbursed for reasonable out of pocket expenses.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH AUDITORS ON ACCOUNTING AND FINANCIAL DISCLOSURES
None.
ITEM 9A.
ITEM 9A. 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 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 at the reasonable assurance level in timely alerting them to material information required to be included in this annual report on Form 10-K.
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 changes in our internal controls over financial reporting or in other factors, that has materially affect, or is reasonably likely to materially affect, our internal controls over financial reporting, including any corrective actions with regard to significant deficiencies or material weaknesses.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item is incorporated by reference from the Company's definitive proxy statement under the captions, "Proposal 1, Election of Directors," "Executive Officers," "Compliance with Section 16(a) of the Exchange Act." The definitive proxy statement is to be filed prior to April 30, 2005.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is incorporated by reference from the Company's definitive proxy statement under the captions "Executive Compensation," "Employment Agreements" and "Compensation of Directors." The definitive proxy statement is to be filed prior to April 30, 2005.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by this item is incorporated by reference from the Company's definitive proxy statement under the captions "Security Ownership of Certain Beneficial Owners" and "Security Ownership of Management." The definitive proxy statement is to be filed prior to April 30, 2005.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item is incorporated by reference from the Company's definitive proxy statement under the caption "Certain Relationships and Related Transactions." The definitive proxy statement is to be filed prior to April 30, 2005.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this item is incorporated by reference from the Company's definitive proxy statement under the caption "Principal Accountant Fees." The definitive proxy statement is to be filed prior to April 30, 2005.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a)Documents filed as a part of this report:
(1)For a list of financial statements, see index to this report on page 28.
(2)Financial Statement Schedules: All schedules have been omitted as the information is either not required or is set forth in the financial statements or the notes thereto.
(3)For a list of exhibits, see "EXHIBIT INDEX" on pages 64 through 68, which is incorporated herein by reference.
(b)See (a) (3) above.
(c)See (a) (2) above. EXHIBIT INDEX
Numbers
Description
3.1
Restated Articles of Incorporation of Tipperary Corporation adopted May 6, 1993, originally filed as Exhibit 3.9 to Amendment No. 1 to Registration Statement on Form S-1 filed with the Commission on June 29, 1993, and incorporated herein by reference.
3.2
Restated Corporate Bylaws of Tipperary Corporation adopted June 28, 1993, originally filed as Exhibit 3.10 to Amendment No. 1 to Registration Statement on Form S-1 filed with the Commission on June 29, 1993, and incorporated herein by reference.
3.3
Articles of Amendment of the Articles of Incorporation of Tipperary Corporation adopted January 25, 2000, originally filed as Exhibit 3.11 to Form 10-QSB for the quarterly period ended December 31, 1999, and incorporated herein by reference.
4.1
Credit Facility Agreement dated March 21, 2003 for AUD$27.5 million between Tipperary Oil & Gas Australia Pty Ltd (ACN 077536871), the borrower, Tipperary Corporation, the Guarantor and Slough Trading Estate Limited, the lender, originally filed as Exhibit 4.77 to Form 10-Q for the quarterly period ended March 31, 2003, and incorporated herein by reference.
4.2
Credit Facility Agreement dated March 21, 2003 for US$8.5 million between Tipperary Corporation, the borrower and Slough Trading Estate Limited, the lender, originally filed as Exhibit 4.78 to Form 10-Q for the quarterly period ended March 31, 2003, and incorporated herein by reference.
4.3
Promissory Note dated March 12, 2004, in the amount of $4.0 million issued by Tipperary Corporation to Slough Estates USA Inc., filed herewith.
4.4
Promissory Note dated March 15, 2005, in the amount of $5.0 million issued by Tipperary Corporation to Slough Estates USA Inc., filed herewith.
4.5
Letters of Variation dated November 25, 2003, July 2, 2004, August 3, 2004 and September 3, 2004, increasing the amount borrowed from Slough Trading Estate Limited from US$8.5 million to US$13.0 million related to the Credit Facility Agreement dated March 21, 2003, for US$8.5 million, filed herewith.
4.6
Comet Ridge Project Facilities Agreement and related agreements dated June 9, 2004, including the Comet Ridge Project TOGA/TCSG Deed of Security of which a portion on Page 59 of this agreement noted by "***" has been omitted pursuant to a request for confidential treatment, and such material has been filed separately with the Securities and Exchange Commission under Rule 246-2 of the Securities Exchange Act of 1934. Agreements originally filed as Exhibits 4.79(a), 4.79(b), 4.79(c), 4.79(d), 4.79(e), 4.79(f), 4.79(g) and 4.79(h) to Form 8-k filed with the Commission on June 30, 2004 and incorporated herein by reference.
4.7
Stock Purchase Agreement dated September 20, 2004, including the Registration Rights Agreement originally filed as Exhibit 4.79 to Form 8-K filed with the Commission on September 24, 2004 and incorporated herein by reference.
10.1
Tipperary Corporation 1997 Long-Term Incentive Plan filed as Exhibit A to the Proxy Statement for its Annual Meeting of Shareholders held on January 28, 1997, originally filed as Exhibit 10.51 to Form 10-Q dated December 31, 1996, and incorporated herein by reference.
10.2
Warrant to Purchase common stock dated December 22, 1998, issued to Slough Estates USA Inc., originally filed as Exhibit 10.58 to Form 10-Q for the quarterly period ended December 31, 1998, and incorporated herein by reference.
10.3
Warrant to Purchase common stock dated December 23, 1999, issued to Slough Estates USA Inc., originally filed as Exhibit 10.60 to Form 10-QSB for the quarterly period ended December 31, 1999, and incorporated herein by reference.
10.4
Warrant to Purchase common stock dated February 9, 2000, issued to James H. Marshall, originally filed as Exhibit 10.70 to Form 10-QSB for the quarterly period ended March 31, 2000, and incorporated herein by reference.
10.5
Warrant to Purchase common stock dated February 9, 2000, issued to James F. Knott, originally filed as Exhibit 10.71 to Form 10-QSB for the quarterly period ended March 31, 2000, and incorporated herein by reference.
10.6
Gas Supply Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) and Energex Retail Pty Ltd (ACN 078 849 055) dated June 23, 2000. Confidential portions of this agreement noted by "***" have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidentiality under Rule 24b-2 of the Securities Exchange Act of 1934, originally filed as Exhibit 10.76 to Form 10-QSB for the quarterly period ended June 30, 2000, and incorporated herein by reference.
10.7
Warrant to Purchase common stock dated May 3, 2000, issued to Charles T. Maxwell, originally filed as Exhibit 10.77 to Form 10-KSB(A) for the transition period ended December 31, 2000, and incorporated herein by reference.
10.8
Warrant to Purchase common stock dated November 30, 2000, issued to D. Leroy Sample, originally filed as Exhibit 10.79 to Form 10-KSB(A) for the transition period ended December 31, 2000, and incorporated herein by reference.
10.9
Purchase and Sale Agreement dated May 4, 2001, by and between Tipperary Oil & Gas Corporation and Koch Exploration Company, originally filed as Exhibit 10.80 to Form S-3, SEC File No. 333-59052, filed with the Commission on July 26, 2001, and incorporated herein by reference.
10.10
Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062294) as Buyer, dated September 28, 2001. Confidential portions of this agreement noted by "***" have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidentiality under Rule 24b-2 of the Securities Exchange Act of 1934, originally filed as Exhibit 10.81 to Form 8-K filed with the Commission on October 18, 2001, and incorporated herein by reference.
10.11
Employment Agreement dated September 18, 2001 between Tipperary Corporation and David L. Bradshaw, originally filed as Exhibit 10.82 to Form 8-K filed with the Commission on October 18, 2001, and incorporated herein by reference.
10.12
Warrant to Purchase common stock dated January 30, 2002, issued to Jeff T. Obourn, originally filed as Exhibit 10.83 to Form 10-KSB for the year ended December 31, 2001, and incorporated herein by reference.
10.13
First Amendment to Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated May 30, 2002, originally filed as Exhibit 10.87 to Form 10-QSB for the quarterly period ended June 30, 2002, and incorporated herein by reference.
10.14
Second Amendment to Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated September 1, 2002, originally filed as Exhibit 10.88 to Form 10-QSB for the quarterly period ended September 30, 2002, and incorporated herein by reference.
10.15
Agreement by Tipperary Oil and Gas (Australia) to provide portion of funds to allow Mitchell Drilling Contractors Pty Ltd. (Mitchell) to purchase a new Soilmec Rig, enter into drilling contract with Mitchell and extend agreement for hire with Mitchell, dated October 7, 2002, originally filed as Exhibit 10.89 to Form 10-QSB for the quarterly period ended September 30, 2002, and incorporated herein by reference.
10.16
Purchase and Sale agreement dated November 27, 2002, between Tipperary Oil & Gas Corporation as Seller and Kerr-McGee Rocky Mountain Corporation as Buyer, originally filed as Exhibit 10.90 to Form 8-K filed with the Commission on December 12, 2002, and incorporated herein by reference.
10.17
Third Amendment to Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated January 1, 2003, originally filed as Exhibit 10.91 to Form 10-KSB for the year ended December 31, 2002, and incorporated herein by reference.
10.18
Gas Supply Term Sheet between Tipperary Oil & Gas (Australia) Pty Ltd (ABN 46 077 536 871) as Seller and Origin Energy Retail Limited (ABN 22 078 868425) as Buyer, dated December 12, 2002. Confidential portions of this agreement noted by an "*" have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidentiality under Rule 24b-2 of the Securities Exchange Act of 1934, originally filed as Exhibit 10.92 to Form 10-KSB for the year ended December 31, 2002, and incorporated herein by reference.
10.19
Warrant to Purchase common stock dated February 3, 2003, issued to Jeff T. Obourn, originally filed as Exhibit 10.93 to Form 10-KSB for the year ended December 31, 2002, and incorporated herein by reference.
10.20
Warrant to Purchase common stock dated February 3, 2003, issued to David L. Bradshaw, originally filed as Exhibit 10.94 to Form 10-KSB for the year ended December 31, 2002, and incorporated herein by reference.
10.21
Warrant to Purchase common stock dated February 3, 2003, issued to Kenneth L. Ancell, originally filed as Exhibit 10.95 to Form 10-KSB for the year ended December 31, 2002, and incorporated herein by reference.
10.22
Employment Agreement dated October 17, 2002, between Tipperary Corporation and Kenneth L. Ancell, originally filed as Exhibit 10.96 to Form 10-KSB for the year ended December 31, 2002, and incorporated herein by reference.
10.23
Fourth Amendment to Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated March 31, 2003, originally filed as Exhibit 10.97 to Form 10-Q for the quarterly period ended June 30, 2003, and incorporated herein by reference.
10.24
Fifth Amendment to Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated June 30, 2003. Confidential portions of this agreement noted by an "*" have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidentiality under Rule 24b-2 of the Securities Exchange Act of 1934, originally filed as Exhibit 10.98 to Form 10-Q for the quarterly period ended September 30, 2003, and incorporated herein by reference.
10.25
Sixth Amendment to Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated December 31, 2003, originally filed as Exhibit 10.99 to Form 10-K for the year ended December 31, 2003, and incorporated herein by reference.
10.26
Seventh Amendment to Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated March 31, 2004, originally filed as Exhibit 10.98 to Form 10-Q for the quarterly period ended March 31, 2004, and incorporated herein by reference.
10.27
Settlement Agreement & Mutual Release dated October 30, 2004, between Tipperary Corporation and Tri-Star Petroleum, originally filed as Exhibit 10.101 to Form 8K filed with Commission on November 4, 2004, and incorporated herein by reference.
10.28
Eighth Amendment to Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated September 30, 2004, filed herewith.
10.29
Extension to Gas Supply Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ABN 46 077 536 871) as Seller and Energex Retail Pty ltd (ABN 97 078849 055) as Buyer, dated December 16, 2004, disclosed on Form 8-K filed with the Commission on December 23, 2004. Confidential portions of this agreement noted by an "***" have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidentiality under Rule 24b-2 of the Securities Exchange Act of 1934, filed herewith.
10.30
Gas Supply Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ABN 46 077 536 871) as Seller and Orica Australia Pty Ltd (ABN 99 004 117 828) as Buyer, dated December 23, 2004, disclosed on Form 8-K filed with the Commission on December 23, 2004. Confidential portions of this agreement noted by an "***" have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidentiality under Rule 24b-2 of the Securities Exchange Act of 1934, filed herewith.
10.31
Gas Supply Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ABN 46 077 536 871) as Seller and Santos QNT Pty Ltd (ABN 33 083 077 196) as Buyer, dated December 30, 2004, disclosed on Form 8-K filed with the Commission on January 4, 2005. Confidential portions of this agreement noted by an "***" have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidentiality under Rule 24b-2 of the Securities Exchange Act of 1934, filed herewith.
10.32
Extension to Employment Agreement, between Tipperary Corporation and Jeff T. Obourn, dated January 6, 2005 and related Employment Agreement dated January 17, 2002, disclosed on Form 8-K filed with the Commission on January 12, 2005, filed herewith.
10.33
Financial Advisory and Investment Banking Services Agreement between Tipperary Corporation and Houlihan Lokey Howard & Zukin Capital, Inc., dated February 22, 2005, disclosed on Form 8-K filed with the Commission on February 25, 2005, filed herewith.
10.34
Ninth Amendment to Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty Ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated December 31, 2004, filed herewith.
21.1
List of subsidiaries, filed herewith.
23.1
Consent of PricewaterhouseCoopers LLP, filed herewith.
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.
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the Registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
TIPPERARY CORPORATION
Date
March 24, 2005
By:
/s/ DAVID L. BRADSHAW David L. Bradshaw, President,
Chief Executive Officer and
Chairman of the Board of Directors
Pursuant to the requirements of the Exchange Act, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
/s/ DAVID L. BRADSHAW David L. Bradshaw
President, Chief Executive Officer and Chairman of the Board of Directors
March 24, 2005
/s/ JOSEPH B. FEITEN Joseph B. Feiten
Chief Financial Officer and Principal Accounting Officer
March 24, 2005
/s/ KENNETH L. ANCELL Kenneth L. Ancell
Executive Vice President-Corporate Development and Director
March 24, 2005
/s/ EUGENE I. DAVIS Eugene I. Davis
Director
March 24, 2005
/s/ DOUGLAS KRAMER Douglas Kramer
Director
March 24, 2005
/s/ MARSHALL D. LEES Marshall D. Lees
Director
March 24, 2005
/s/ CHARLES T. MAXWELL Charles T. Maxwell
Director
March 24, 2005
/s/ D. LEROY SAMPLE D. Leroy Sample
Director
March 24, 2005
PART I
ITEMS 1 AND 2. DESCRIPTION OF BUSINESS AND PROPERTIES
ITEM 3. LEGAL PROCEEDINGS
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
ITEM 6. SELECTED FINANCIAL DATA
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Revenues and Volumes
Expenses and Foreign Exchange Gains/Losses
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
Foreign Currency Risk
Interest Rate Risk
Commodity Price Risk
ITEM 8. FINANCIAL STATEMENTS
TIPPERARY CORPORATION AND SUBSIDIARIES Consolidated Balance Sheets ($ in thousands except per share data)
TIPPERARY CORPORATION AND SUBSIDIARIES Consolidated Statements of Operations (in thousands, except per share data)
TIPPERARY CORPORATION AND SUBSIDIARIES Consolidated Statement of Stockholders' Equity (in thousands)
TIPPERARY CORPORATION AND SUBSIDIARIES Consolidated Statements of Cash Flows (in thousands)
TIPPERARY CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
SIGNATURES