-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, DACtqNwsp5L5CH/k/RRwVKC2rXb6tRfqtiAuBICqC2zKULofXU3ExCuDKT9rPKfW iOy9le7NZeaSMWi6PvSVKg== 0001047469-98-045360.txt : 19981230 0001047469-98-045360.hdr.sgml : 19981230 ACCESSION NUMBER: 0001047469-98-045360 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 7 CONFORMED PERIOD OF REPORT: 19980930 FILED AS OF DATE: 19981229 FILER: COMPANY DATA: COMPANY CONFORMED NAME: TIPPERARY CORP CENTRAL INDEX KEY: 0000098410 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 751236955 STATE OF INCORPORATION: TX FISCAL YEAR END: 0930 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: SEC FILE NUMBER: 001-07796 FILM NUMBER: 98777482 BUSINESS ADDRESS: STREET 1: 633 17TH ST STE 1550 CITY: DENVER STATE: CO ZIP: 80202 BUSINESS PHONE: 3032939379 MAIL ADDRESS: STREET 1: 633 SEVENTEENTH ST STREET 2: SUITE 1550 CITY: DENVER STATE: CO ZIP: 80202 FORMER COMPANY: FORMER CONFORMED NAME: TIPPERARY LAND & EXPLORATION CORP DATE OF NAME CHANGE: 19730522 FORMER COMPANY: FORMER CONFORMED NAME: TIPPERARY LAND CORP DATE OF NAME CHANGE: 19690521 10-K405 1 FORM 10-K405 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, DC 20549 FORM 10-K X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE - --------- SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended September 30, 1998 OR - --------- TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _______________ to ________________ Commission file number 1-7796 TIPPERARY CORPORATION (Exact name of registrant as specified in its charter) Texas 75-1236955 (State or other jurisdiction of (I.R.S. employer incorporation or organization) identification no.) 633 Seventeenth Street, Suite 1550 Denver, Colorado 80202 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (303) 293-9379 SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: Title of each class Name of each exchange on which registered ------------------- ----------------------------------------- Common Stock, $.02 par value American Stock Exchange SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Sections 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ___x___ No _______ Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K /x/. Aggregate market value of voting stock held by non-affiliates of the registrant as of December 1, 1998, was $15,421,000. Shares of the registrant's Common Stock outstanding as of December 1, 1998: 13,133,955 shares. Documents incorporated by reference and the Part of the Form 10-K into which the document is incorporated: Definitive Proxy Statement for the 1999 Annual Meeting of Shareholders filed within 120 days after the fiscal year ended September 30, 1998 (Part III). PART I ITEMS 1 AND 2. DESCRIPTION OF BUSINESS AND PROPERTIES GENERAL Tipperary Corporation and its subsidiaries (the "Company") are principally engaged in the exploration for and development and production of crude oil and natural gas. The Company was organized as a Texas corporation in January 1967. Its executive offices are located at 633 Seventeenth Street, Suite 1550, Denver, Colorado 80202. The Company's major areas of operations are in the Permian Basin, the Rocky Mountain and Mid-Continent areas of the United States, and in Queensland, Australia, where it is involved in a coalbed methane project. The Company seeks to increase its oil and gas reserves through exploration, exploitation and development projects and occasionally through the purchase of producing properties. The Company's capital expenditures since fiscal 1993 have been directed toward exploitation, exploration and development projects discussed herein, and the acquisition of additional interests in the Comet Ridge coalbed methane project in Queensland, Australia. STRATEGY The Company's international exploration and development efforts, and the majority of its capital investment over the past few fiscal years, have been focused on the Comet Ridge coalbed methane project in Queensland, Australia, in which the Company holds a non-operating interest. Beginning in fiscal 1996, the Company's strategy was to increase its ownership interest in the project and, together with its co-venturers, construct a gathering system, initiate gas contract negotiations and obtain financing proposals. During fiscal 1996, 1997 and 1998, the Company increased its interest in the project from 30% to 55.75%. During fiscal 1997 and 1998, the Company and its co-venturers installed gathering lines and compression facilities and connected nine wells in the core Fairview area to the pipeline system serving the Queensland markets. The Company began selling gas from the Comet Ridge project during February 1998 and was selling approximately 2,000 Mcf per day as of September 30, 1998. The Company's strategy with respect to this project during the next several years is to participate with its co-venturers in drilling and connecting additional development wells and conducting further exploration activities. As more fully discussed below, subsequent to September 30, 1998, the Company received from its largest shareholder a commitment for a $6 million project financing loan to fund an eight-well drilling program proposed by the Company. The Company's domestic strategy has been to acquire undeveloped leasehold acreage with the intent of identifying exploratory prospects and then initiating drilling programs with industry partners. The focus area of this strategy over the past few fiscal years has been the Williston Basin of Montana and North Dakota. In fiscal 1996 the Company secured funding for one of its two major projects through the sale of partial interests to two industry partners which are participating in the exploration activities. During fiscal 1997 and 1998, the Company participated in drilling seven wells in the Williston Basin, of which six were completed as producers. Since fiscal 1996, exploitation and exploration projects have resulted in incremental production volumes which have mitigated natural production declines and production volumes lost due to property sales. The Company's domestic oil and gas operations have been negatively impacted by the severe decline in oil prices since September 30, 1997. In addition to causing negative operating cash flows, these price declines have affected the value of the Company's domestic oil and gas properties and deferred tax asset and, because of the decrease in collateral value, caused a reduction of the Company's borrowing base with its bank. As a result of these depressed oil prices and, to a lesser extent, gas prices, the Company's focus in the near term will be to develop the Comet Ridge project and to evaluate the economics of existing domestic producing properties. A limited amount of working capital may be available for domestic exploration projects, but drilling activities in the Williston Basin have been discontinued at present pending a sufficient recovery in crude oil prices. 1 SIGNIFICANT DEVELOPMENTS DURING THE YEAR ENDED AND SUBSEQUENT TO SEPTEMBER 30, 1998 WRITE-DOWN OF OIL AND GAS PROPERTIES Under the full cost method of accounting, capitalized oil and gas property costs, less accumulated amortization and related deferred income taxes, may not exceed the sum of the present value of future net revenues from proved reserves and the lower of cost or market value of unproved properties, less related income tax effects. This "ceiling test" must be performed quarterly on a country by country basis. Based on June 30, 1998 oil and gas prices, the Company's United States full cost pool book value exceeded the ceiling test value by $1,399,000. Accordingly, the book value of domestic oil and gas properties was written down by this amount as of June 30, 1998. See the Consolidated Financial Statements herein. WRITE-DOWN OF DEFERRED INCOME TAX ASSET Under Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes," the Company has recorded a $21 million asset for the future benefit of its net operating tax loss carryforwards and other tax benefits. As of September 30, 1998, this asset was offset by a valuation allowance of approximately $19 million based on management's projections of realizability of the gross deferred tax asset. Fluctuations in industry conditions and trends warrant periodic management reviews of the recorded valuation allowance to determine if an increase or decrease in such allowance is appropriate. As of June 30, 1998, New York Mercantile Exchange ("NYMEX") oil and gas prices had decreased approximately 30% and 20%, respectively, compared to prices as of September 30, 1997. As a result of these price decreases, management revised its assumptions used in projections of taxable income and utilization of net operating loss carryforwards. These revisions, combined with recent net operating tax losses, and the expiration by 2001 of $31 million of approximately $43 million in total tax net operating loss carryforwards, led management to conclude that the current impact of lower oil and gas prices warranted an increase of $1,618,000 in the deferred tax asset valuation allowance as of June 30, 1998, with a corresponding charge to deferred tax expense. COMET RIDGE COALBED METHANE PROJECT Following the construction of the initial gathering system completed in early fiscal 1998, the Company entered into the first contract to sell gas from the Comet Ridge project in February 1998. The Company's net sales increased from an initial rate of approximately 1,000 Mcf per day to approximately 2,000 Mcf per day as of September 30, 1998. The Company has recently entered into a five-year contract to supply up to approximately 2,800 Mcf per day, net to the Company's interest, beginning in January 1999. This contract will replace volumes being sold under the existing contracts. The Company and the operator of the Comet Ridge project have had disputed issues with regard to the operation of the project and in August 1998, the Company filed a lawsuit against the operator in an effort to resolve them. See Note 8 to the Company's Consolidated Financial Statements herein. The Company believes that these disputes will not cause a delay in the proposed development of the project and that their resolution will accelerate both future drilling plans and opportunities to enter into new sales contracts. DEBT AND EQUITY FINANCING In December 1998, the Company received debt and equity financing of $11,700,000 from Slough Estates USA Inc. ("Slough"), the Company's largest shareholder. This financing is comprised of a loan in the amount of $6,000,000 to be used for development of the Comet Ridge project; $4,000,000 from the issuance of 2,000,000 shares of common stock and an additional loan in the amount of $1,700,000. The commitment for the $6,000,000 loan was made to the Company's Australian subsidiary and the proceeds from this loan will be used to fund the drilling of eight wells and to expand the gathering system on the Comet Ridge project. The loan is evidenced by a five-year note bearing interest at the rate of 10% per annum. The terms of the note also provide that Slough will receive additional payments based upon a royalty of 7% of gross revenues from both the existing and 2 eight proposed wells until the loan is paid in full, after which it will be on the eight new wells for the life of those wells. The Company's share of estimated costs for this development project is approximately $3,300,000. The balance of the proceeds will be available for the Company to extend loans to the remaining working interest owners in the project for their proportionate share of the capital costs of this drilling program. In addition to the promissory note for $6,000,000, the Company will transfer to Slough ten percent of the common stock of the Australian subsidiary. The loan of $1,700,000, together with the $2,700,000 note payable as of September 30, 1998, and an additional $1,100,000 borrowed subsequent to September 30, 1998, are due under the terms of a three-year note for $5,500,000 bearing interest at the London Interbank Offered Rate ("LIBOR") plus 3.5%. The $1,700,000 proceeds from this loan and the $4,000,000 proceeds from the issuance of common stock were used to reduce bank debt by $4,700,000, which brings the current loan balance due the bank to the new borrowing base level of $11,800,000. The remaining $1,000,000 of the proceeds will be used by the Company for working capital. In connection with this debt and equity financing, the Company also issued to Slough warrants to purchase 500,000 shares of the Company's common stock at $3.00 per share, exercisable during a five-year period beginning in December 2000 and ending in December 2005. 3 EXPLORATION AND DEVELOPMENT ACTIVITIES INTERNATIONAL - COMET RIDGE COALBED METHANE PROJECT. In April 1992, the Company acquired its original non-operating interest in the Comet Ridge coalbed methane project in the Bowen Basin located in Queensland, Australia. As of September 30, 1998, the co-venturers conducting the project (the "Group") owned an Authority to Prospect ("ATP") granted by the Queensland government covering approximately 1,088,000 acres. The holder of an ATP may be granted petroleum leases upon establishing to the satisfaction of the Queensland government that commercial deposits of petroleum have been discovered. During fiscal 1996 the Group was granted petroleum leases covering approximately 167,000 acres in the area known as "Fairview," which is in the southern portion of the ATP. The Group has applied for an additional ten leases covering approximately 550,000 acres. Two of these additional leases are in the Fairview area, and eight are in the northern portion of the ATP. The Group's ATP currently extends through October 31, 2000, and requires certain minimum expenditures, based on current exchange rates, of approximately US $350,000 and US $725,000 in the years ending October 31, 1999, and 2000, respectively. The Company will be responsible for its pro rata share of these expenditures. During fiscal 1998, the Company increased its ownership in the rights under the Joint Operating Agreement covering the Comet Ridge project from 50.75% to 55.75% with the acquisition of an additional 5% interest from an unaffiliated interest holder for approximately $3.2 million. The Company's interest in the Comet Ridge project is 55.75% of capital costs and 52.50% of operating expenses, and its net revenue interest is 46.34% prior to project payout. Subsequent to project payout, the Company's interest is 45.35% of capital and operating expenses, and its net revenue interest is 39.99%. As of September 30, 1998, the Group had drilled 19 wells on its ATP acreage, of which 18 are in the Fairview area in the southern portion of the ATP and one well is shut in pending completion in the Dawson area in the northern portion of the ATP. During fiscal 1998, the Group completed construction of gas gathering lines and compression facilities, which connect nine wells, through a 17-mile spur line, to a pipeline system serving the Queensland markets. Subsequent to September 30, 1998, the Group drilled and cased two additional wells in the Fairview area, both of which are pending completion. The Company has recently proposed an eight-well drilling program and expansion of the gathering system in the Fairview area. It also offered financing to those of its co-venturers requiring it. This was made possible by the $6 million loan obtained from Slough subsequent to September 30, 1998. See the discussion of "Debt and Equity Financing" above in "Significant Developments During the Year Ended and Subsequent to September 30, 1998." DOMESTIC - MISSOURI RIVER PROJECT. The Company owns an average 43.75% undivided interest in approximately 38,000 acres in its Missouri River project area in the Williston Basin of Montana. After conducting a three-dimensional seismic survey in 1995, the Company drilled a dry hole on the first prospect tested in fiscal 1996. As of September 30, 1996, the Company's investment in the project totaled approximately $2,420,000. An additional $50,000 was incurred during fiscal 1997 and $604,000 in fiscal 1998, bringing the total investment to $3,074,000 as of September 30, 1998. During fiscal 1997, the Company drilled a second test well. This well was completed as a producer in fiscal 1998. DIVIDE PROJECT. During fiscal 1996, the Company assembled a 30,000 acre leasehold position in Divide County, North Dakota, and entered into exploration agreements with two industry partners. The parties have identified numerous prospects in the Divide Project area of the Williston Basin. Seismic acquisition commenced in November 1996 and drilling operations began in the fourth quarter of fiscal 1997. One well drilled was a dry hole, while the other was successfully completed during fiscal 1998. The Company's share of costs for these two wells was approximately $600,000. OTHER WILLISTON BASIN PROJECTS. During fiscal 1997, the Company participated in a three-well drilling program with industry partners. Of the three wells drilled, two were completed and are currently producing. The third underwent a successful recompletion attempt in fiscal 1998 and is also currently producing. During fiscal 1998, an additional well was drilled and completed at a cost of approximately $560,000 to the Company. The Company continues to evaluate the potential of this area and may conduct new exploratory drilling in the future. All of the Company's exploratory drilling in the Williston Basin has been curtailed as a result of the severe decline in crude oil prices. The Company will make an effort to retain its acreage position as long as feasible and will conduct minor activities necessary to generate prospects which may be drilled when oil prices increase significantly. 4 DRILLING ACTIVITIES Information concerning the number of gross and net wells drilled by the Company during fiscal 1998, 1997, and 1996 is as follows:
United States Australia Total ---------------- ---------------- ---------------- Gross Net Gross Net Gross Net ------- ----- ------- ----- ------- ----- September 30, 1998 Exploratory Productive 4 1.52 - - 4 1.52 Dry 2 1.25 - - 2 1.25 Development Productive 1 0.05 - - 1 0.05 Dry - - - - - - Total Productive 5 1.57 - - 5 1.57 Dry 2 1.25 - - 2 1.25 September 30, 1997 Exploratory Productive 2 0.25 - - 2 0.25 Dry - - - - - - Development Productive 4 0.69 3 1.52 7 2.21 Dry 3 0.11 - - 3 0.11 Total Productive 6 0.94 3 1.52 9 2.46 Dry 3 0.11 - - 3 0.11 September 30, 1996 Exploratory Productive 2 0.07 - - 2 0.07 Dry 2 0.95 - - 2 0.95 Development Productive 5 0.36 - - 5 0.36 Dry - - - - - - Total Productive 7 0.43 - - 7 0.43 Dry 2 0.95 - - 2 0.95
MAJOR PRODUCING PROPERTIES The following is a brief description of the Company's major producing areas: UNITED STATES WILLISTON BASIN. The Company operates 33 wells in the Williston Basin of North Dakota and Montana. With discounted future net revenues of approximately $4,755,000, the Company's Williston Basin assets comprise approximately 28% of the Company's total domestic reserve value at September 30, 1998, and account for 28% of the Company's daily oil production and 14% of its daily gas production volumes. Exploitation projects in this area during fiscal 1996 resulted in additional proved reserves of 186,000 barrels of oil equivalent ("BOE") with a discounted future net revenue value of $972,000 as of September 30, 1996. During fiscal 1997, the Company participated in a three-well drilling program in this area, with a 12.5% interest in each of the three wells. Two of the wells added proved reserves of 30,000 BOE with a discounted future net revenue value of $245,000 as of September 30, 1997, net to the Company's interest. During fiscal 1998, the Company participated in the drilling of three wells in the Williston Basin resulting in the addition of 5 proved reserves of 264,000 BOE with a discounted future net revenue of $1,167,000 as of September 30, 1998. The Company believes further exploration potential exists on its existing properties, and is currently reviewing other prospects in the Williston Basin. Additional drilling will not be undertaken, however, until oil prices increase substantially. POWDER RIVER BASIN. The Company's reserves in the Powder River Basin in northeastern Wyoming had discounted future net revenues of $805,000, or 5%, of the Company's total domestic reserve value as of September 30, 1998. Net production from the Powder River Basin accounts for approximately 20% of the Company's daily oil production. The Company owns non-operating interests in seven waterflood projects in this area. These projects are currently marginal because of the depressed crude oil prices, and some may have to be shut in. EAST TEXAS. The West Buna Field in Jasper and Hardin Counties represents a significant percentage of the Company's Texas reserves. Discounted future net revenues from the Company's non-operating interest in this field were $5,378,000, approximately 32% of the Company's domestic total, as of September 30, 1998. Of this total, $2,402,000 was attributable to proved undeveloped reserves. During fiscal 1998, net oil and gas production from this field was approximately 6% and 16%, respectively, of the Company's total production volumes. PERMIAN BASIN. The Company commenced oil and gas operations in Lea County, New Mexico in 1969 when it first acquired interests in the North Bagley Field. After purchasing additional interests throughout the field in 1984, North Bagley became and today remains the Company's largest single concentration of operated properties. As of September 30, 1998, the Company's North Bagley properties had discounted future net revenues of $2,120,000, representing approximately 13% of the Company's total domestic reserve value. The Company's current net daily production from the North Bagley Field is distributed among 37 wells operated by the Company, and represents approximately 12% and 39%, respectively, of the Company's total daily oil and gas production volumes. In addition to North Bagley, the Company owns and operates properties in several other Lea County fields, including the Mescalero and Shipp fields. Many of these properties have become marginal to uneconomic based upon recent oil prices. The Company is currently evaluating the individual wells and may determine to temporarily shut in or permanently plug and abandon some of the wells. AUSTRALIA BOWEN BASIN. The Company has a non-operating interest in the Comet Ridge coalbed methane project in the Bowen Basin located in Queensland, Australia. As of September 30, 1998, the Company and its co-venturers had drilled 19 wells, of which 18 are producing or capable of producing and nine wells are connected to a pipeline system. Subsequent to September 30, 1998, the Group drilled and cased two additional wells, both of which are awaiting completion. See the discussion of the Comet Ridge coalbed methane project in "Exploration and Development Activities - International." PRODUCTION The Company's net oil and gas production for fiscal 1998, 1997 and 1996 was as follows:
United States Australia Total --------------------- ---------------------- ---------------------- Oil Gas Oil Gas Oil Gas (Bbl) (Mcf) (Bbl) (Mcf) (Bbl) (Mcf) ------- --------- ------- --------- ------- --------- 1998 426,000 1,320,000 - 371,000 426,000 1,691,000 1997 481,000 1,565,000 - - 481,000 1,565,000 1996 470,000 1,550,000 - - 470,000 1,550,000
6 AVERAGE PRICES AND AVERAGE LIFTING COSTS The following table presents certain average price and lifting cost information for each of the years in the three-year period ended September 30, 1998:
Average price Price range ---------------------- ------------------------------------------------- Oil Gas Average lifting Oil Gas ----------------------- ---------------------- cost per (Bbl) (Mcf) High Low High Low Equivalent Bbl --------- --------- ---------- --------- --------- --------- --------------- United States: - -------------- 1998 $ 14.63 $ 1.72 $ 18.73 $ 11.37 $ 2.04 $ 1.34 $ 6.73 1997 $ 19.36 $ 2.22 $ 22.63 $ 14.70 $ 3.73 $ 1.68 $ 7.21 1996 $ 17.76 $ 1.68 $ 20.45 $ 14.57 $ 1.91 $ 1.35 $ 7.30 Australia: - ---------- 1998 $ - $ 1.22 $ - $ - $ 1.32 $ 1.16 $ 7.70 1997 $ - $ - $ - $ - $ - $ - $ - 1996 $ - $ - $ - $ - $ - $ - $ -
PRODUCING WELLS AND ACREAGE The following table sets forth information with respect to the Company's producing wells and acreage as of September 30, 1998:
Producing wells Acreage Oil Gas Producing Undeveloped ------------------------------------ -------------------------------------- State/Country Gross Net Gross Net Gross Net Gross Net - ------------- ----- --- ----- --- ----- --- ----- --- Alaska(1) - - - - - - 640 129 Colorado 51 1.95 - - 2,631 201 63,734 62,860 Montana 50 7.98 - - 9,279 1,692 54,430 18,186 Nebraska 8 1.70 - - 1,560 334 640 123 New Mexico 72 42.00 165 4.59 5,724 3,672 404 291 North Dakota 86 17.68 - - 16,081 3,579 88,746 28,571 Oklahoma 7 2.02 15 0.97 3,770 574 1,120 744 Texas 38 4.23 36 7.06 14,064 2,309 1,200 304 Wyoming 46 4.30 - - 15,129 1,368 19,473 3,179 Australia(2) - - 18 9.45 5,000 2,788 162,000 90,315 ----- ----- ----- ----- ------ ------ ------- ------ Total 358 81.86 234 22.07 73,238 16,517 392,387 204,702 ===== ===== ===== ===== ====== ====== ======= =======
(1) The Company owns 129 net working interest acres (173 net acres including additional overriding royalty interests) in the Point Thomson Unit located on the Alaska North Slope. The Company's interest represents less than 1% of the total unit, which is operated by a major oil and gas company. Although engineering studies and production tests of wells drilled within the unit boundaries have confirmed the existence of substantial oil and gas reserves, the Company has excluded these reserves from its proved reserves reflected in Note 9 to the Company's Consolidated Financial Statements due to the lack of a current market and/or pipeline facilities. Working interest owners continue to evaluate the economics of the property and periodically file updated "Plans of Development" with the State of Alaska, but it is not known when, if ever, market conditions will justify the economics of constructing pipeline facilities to the property. (2) As of September 30, 1998, the Company owned rights to a non-operating interest in an Authority to Prospect ("ATP") covering approximately 1,088,000 acres in the Bowen Basin of Queensland, Australia, of which 167,000 acres are covered by petroleum leases. The 18 producing wells are in the Fairview area in the southern portion of the ATP. 7 The Company's domestic undeveloped leases have various primary terms ranging from one to ten years. The expiration of any leasehold interest or interests would not have a material adverse financial effect on the Company. Substantially all of the Company's domestic oil and gas properties either have been or may be pledged as security for bank debt. While mortgages have not been filed against many of the properties, the Company recently agreed to pledge other unencumbered properties. See Note 5 to the Company's Consolidated Financial Statements. SALES CONTRACTS In the United States, the Company sells its domestic oil and gas production to numerous purchasers, generally under short-term contracts. While certain gas sales are dedicated to gas processing plants for longer terms, a substantial portion of residue gas and plant liquids are typically sold by the plants on a short-term basis. Since numerous purchasers compete to purchase both oil and gas from the Company's properties, the Company does not believe that the loss of any single existing purchaser would have a material adverse effect on its financial condition or results of operations. The Company is not obligated to provide a fixed and determinable quantity of oil or gas in the future under existing contracts and agreements. In Australia, the Company began selling gas under short-term gas contracts in February 1998 and in September 1998, the Company entered into a five-year contract to supply up to approximately 5,500 Mcf (2,800 net) of gas per day beginning January 1999. See the discussion above in -"Exploration and Development Activities - International." PRICING During fiscal 1998, approximately 73% of the Company's domestic oil and gas revenues were attributable to crude oil sales. Both oil and natural gas prices in the United States are subject to significant fluctuations. Natural gas prices fluctuate based primarily upon weather patterns and regional supply and demand, and crude oil prices fluctuate based primarily upon worldwide supply and demand. The majority of the Company's domestic gas sales are through "percentage of proceeds" contracts with gas processing plant owners, whereby the Company receives various percentages of both residue gas and plant liquids sales proceeds. Residue gas sold by the respective gas processing plant owner under these contracts may be sold at "spot" prices or longer term contract prices. The Company has in recent years hedged significant portions of its crude oil sales and a lesser amount of gas sales through both "swap" agreements and put options with financial institutions and direct contracts in the NYMEX. Under swap agreements, the Company usually receives a floor price, but retains 50% of price increases above the floor. Under put options, the Company has the right, but not the obligation, to exercise the option and receive the strike price for the volume of oil or gas subject to the option agreement. As of September 30, 1998, the Company had in place a swap agreement covering 5,000 barrels of oil production for each of October and November 1998 at $16.00 per barrel. The Company has not entered into any additional agreements to hedge oil production and none of the Company's gas production is currently hedged for periods subsequent to September 30, 1998. See the discussion of hedging activities in "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources," and Note 1 to the Company's Consolidated Financial Statements. COMPETITION AND OTHER RISKS The Company competes for available leasehold acreage with companies which are substantially larger and may have greater financial resources. Notwithstanding such competition, the Company believes that its current leasehold position will provide an adequate inventory of prospects for the exploratory activity the Company expects to carry on for the next two to three years. Recent oil price declines, however, have caused the Company to suspend drilling plans. If the low price levels continue for an extended period, the Company may begin to relinquish exploration leasehold acreage through expiration of term leases. This report contains certain statements of future business plans and objectives and statements in "Management's Discussion and Analysis of Financial Condition and Results of Operations," which may be considered forward-looking. These forward-looking statements are subject to risks and uncertainties. Although the Company believes that its expectations are based on reasonable assumptions, it can give no assurance that its goals will be achieved. The operations of the Company, both domestically and internationally, are subject to risks including, but not limited to, all of the risks that are encountered in the drilling and completing of wells, along with standard risks of oil and gas 8 operations, uninsured hazards, volatile oil and gas prices and uncertain markets and governmental regulation. For a discussion of these and other risks which relate to the forward-looking statements contained herein, please see "Risk Factors" in the Company's Registration Statement on Form S-8, SEC File No. 333-40589, which discussion is incorporated herein by reference, along with other cautionary statements in this report. OTHER BUSINESS PROPERTIES In addition to these primary business activities, the Company has a royalty interest in an Australia bauxite deposit and a discovered but undeveloped oil and gas property in Alaska. Neither of these assets currently generates revenues and management anticipates the Company will not be devoting any significant efforts or expenditures on these projects during fiscal 1999. PROVED OIL AND GAS RESERVES Information concerning the Company's estimated proved oil and gas reserves and discounted future net cash flows applicable thereto for fiscal 1998, 1997 and 1996 is included in Note 9 to the Company's Consolidated Financial Statements herein. In fiscal 1998, information concerning portions of the Company's estimated proved oil and gas reserves was provided to the U.S. Department of Energy. SEGMENT INFORMATION AND MAJOR CUSTOMERS The Company has one business segment: Oil and Gas Exploration, Production and Development. The Company had sales in excess of 10% of total revenues to three unaffiliated oil and gas customers during fiscal 1998 totaling 43%, three unaffiliated oil and gas customers during fiscal 1997 totaling 41%, and three unaffiliated oil and gas customers during fiscal 1996 totaling 42%. The Company does not believe that the loss of any existing purchaser would have a material adverse impact on its ability to sell its production to another purchaser at similar prices. UNITED STATES REGULATIONS GENERAL. The production, transmission and sale of crude oil and natural gas in the United States is affected by numerous state and federal regulations with respect to allowable well spacing, rates of production, bonding, environmental matters and reporting. Future regulations may change allowable rates of production or the manner in which oil and gas operations may be lawfully conducted. Although oil and gas may currently be sold at unregulated prices, such sales prices have been regulated in the past by the federal government and may be again in the future. STATE REGULATION. Oil and gas operations are subject to a wide variety of state regulations. Administrative agencies in such jurisdictions may promulgate and enforce rules and regulations relating to virtually all aspects of the oil and gas business. ENVIRONMENTAL MATTERS. The Company's business activities are subject to changing federal, state and local environmental laws and regulations. The existence of such regulations has had no material effect on the Company's operations and the cost of such compliance has not been material to date. During fiscal 1995 and 1996, the Company incurred approximately $44,000 and $6,000, respectively, in further costs for remediation of previously used facilities. In fiscal 1997, the Company incurred $185,000 to remediate and close ten earthen disposal pits. Costs of approximately $30,000 were incurred in fiscal 1998 to monitor environmental compliance issues. Although the Company expects to incur additional environmental clean-up expenditures in the future, at this time it is not aware of any such expenditures that would have a material adverse effect on its financial condition or results of operations. AUSTRALIA REGULATIONS COMMONWEALTH OF AUSTRALIA REGULATIONS. The regulation of the petroleum industry in Australia is similar to that of the United States, in that regulatory controls are imposed at both the state and commonwealth levels. Specific commonwealth regulations impose environmental, cultural heritage and native title restrictions on accessing resources in Australia. These regulations are in addition to any state level regulations. Native title legislation was enacted in 1993 9 in order to provide a statutory framework for deciding questions such as where native title exists, who holds native title and the nature of native title which were left unanswered by a 1992 Australian High Court ("Court") decision. The Commonwealth and Queensland State governments have passed amendments to this legislation to clarify uncertainty in relation to the evolving native title legal regime in Australia created by the decision in a 1996 Court case. Each authority to prospect, petroleum lease and pipeline license must be examined individually in order to determine validity and native title claim vulnerability. STATE OF QUEENSLAND REGULATIONS. The regulation of exploration and recovery of petroleum resources within a state is governed by state level legislation. This legislation regulates access to the resource, construction of pipelines and the royalties payable. There is also specific legislation governing cultural heritage, native title and environmental issues. Environmental matters are highly regulated at the state level, with most states having in place comprehensive pollution and conservation regulations. In particular, petroleum operations in Queensland must comply with the new Environmental Protection Act and associated Environmental Protection Policy for mining and any tenure condition requiring compliance with the Australian Petroleum Production and Exploration Association Code of Practice. The cost to comply with the foregoing regulations cannot be estimated at this time, although management believes that costs will not significantly hinder or delay the Company's plans in Australia. AUSTRALIA CRUDE OIL AND GAS MARKETS. The Australia and Queensland onshore crude oil and gas markets are deregulated, with prices being determined exclusively by market forces. A national regulatory framework for the natural gas market in Australia has commenced its roll out (on a state by state basis), with Queensland expected to implement legislative changes in 1999. The National Gas Access Regime (the "Regime") is being developed by a group of government and oil and gas industry representatives. Among the objectives of the Regime are to provide a process for establishing third party access to natural gas pipelines, to facilitate the development and operation of a national natural gas market, to promote a competitive market for gas in which customers are able to choose their supplier, and to provide a right of access to transmission and distribution networks on fair and reasonable terms and conditions. The Company cannot currently ascertain the impact of the Regime but believes it will benefit the Company. OFFICE FACILITIES The principal executive offices of the Company are located at 633 Seventeenth Street, Suite 1550, Denver, Colorado 80202, where it leases approximately 11,000 square feet of office space from an unaffiliated party. EMPLOYEES At September 30, 1998, the Company employed a total of 19 persons, including its officers. None of the Company's employees are represented by unions. The Company considers its relationship with its employees to be excellent. ITEM 3. LEGAL PROCEEDINGS Information concerning material legal proceedings involving the Company is included in Note 8 to the Company's Consolidated Financial Statements. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS The Company did not submit any matter to a vote of its security holders during the fourth quarter of its fiscal year ended September 30, 1998. 10 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The Company's common stock is listed and has been trading on the American Stock Exchange since April 16, 1992. As of December 1, 1998, there were approximately 2,000 holders of record of the Company's common stock. The table below sets forth the high and low closing prices for the common stock of the Company for the periods indicated:
Fiscal Fiscal Quarter ended 1998 1997 ------------- ---------------- --------------- High Low High Low ---- --- ---- --- December 31 $6.63 $3.75 $5.06 $3.63 March 31 $4.63 $3.75 $4.94 $4.38 June 30 $4.25 $2.25 $5.19 $3.63 September 30 $3.00 $1.63 $5.00 $4.00
The Company has not paid any cash dividends on its common stock and does not expect to pay any dividends in the foreseeable future. The Company's bank credit facility provides that dividends may not be paid by the Company without the prior approval of the bank. The Company intends to retain any earnings to provide funds for operations and expansion of its business. 11 ITEM 6. SELECTED FINANCIAL DATA Selected financial data (in thousands, except per share data) for each of the years in the five-year period ended September 30, 1998, is as follows:
1998 1997 1996 1995 1994 ---------- -------- ---------- ---------- ---------- Revenues from continuing operations $ 9,082 $ 12,951 $ 11,136 $ 11,837 $ 13,884 ========== ======== ========== ========== ========== Income (loss) from: Continuing operations $ (6,398)(1) $ 472 $ (790) $ (1,284) $ (1,638)(2) Discontinued operations - - - - (214) Cumulative effect of accounting change - - - 3,000 (3) ---------- -------- ---------- ---------- ---------- Net income (loss) $ (6,398) $ 472 $ (790) $ (1,284) $ 1,148 ========== ======== ========== ========== ========== Income (loss) per common share: Continuing operations $ (.49) $ .04 $ (.07) $ (.11) $ (.15) Discontinued operations - - - - (.02) Cumulative effect of accounting change - - - - .27 ---------- -------- ---------- ---------- ---------- Net income (loss) - basic and diluted $ (.49) $ .04 $ (.07) $ (.11) $ .10 ========== ======== ========== ========== ========== Weighted average shares outstanding 13,118 13,050 11,807 11,190 11,311 ========== ======== ========== ========== ========== Total assets $ 50,760 $ 54,995 $ 52,098 $ 47,044 $ 48,253 ========== ======== ========== ========== ========== Total long-term debt $ 19,200 $ 13,844 $ 13,994 $ 15,746 $ 15,746 ========== ======== ========== ========== ========== Working capital $ 1,045 $ 1,381 $ 4,011 $ 5,455 $ 4,965 ========== ======== ========== ========== ========== Working capital provided by operations $ 1,015 $ 5,201 $ 3,285 $ 3,917 $ 5,097 ========== ======== ========== ========== ========== Stockholders' equity $ 30,280 $ 36,488 $ 36,016 $ 29,818 $ 31,031 ========== ======== ========== ========== ==========
- -------------- (1) Includes $1,399 write-down of oil and gas properties and $1,618 write-down of deferred tax asset. (2) Includes $2,021 write-down of oil and gas properties. (3) Change in method of accounting for income taxes. 12 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following is a discussion of the Company's financial condition and results of operations. This discussion should be read in conjunction with the Consolidated Financial Statements of the Company 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 the Company itself. Words such as "may," "will," "expect," "anticipate," "estimate" or "continue," or comparable words are intended to identify such forward-looking statements. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict with regard to timing, extent, likelihood and degree of occurrence. Therefore, actual results and outcomes may materially differ from what may be expressed or forecasted in such forward-looking statements. Furthermore, the Company undertakes no obligation to update, amend or clarify forward-looking statements, whether as a result of new information, future events or otherwise. Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to, changes in production volumes, worldwide supply and demand which affect commodity prices for petroleum natural resources, the timing and extent of the Company's 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, the effect of existing and future laws, governmental regulations and the political and economic climate of the United States and Australia, the effect of hedging activities, and conditions in the capital markets. GENERAL During the past three fiscal years, the Company's primary focus has been directed toward exploratory and development drilling activities in both the United States and in Queensland, Australia. Approximately 62% of the Company's capital expenditures has been applicable to the Comet Ridge coalbed methane project in Australia. In the United States during this period, the Company has used its remaining available capital to acquire undeveloped leasehold acreage, identify exploratory prospects and participate in exploratory and development drilling and exploitation projects. These projects have resulted in additional reserves of approximately 831,000 barrels of oil equivalent, mitigating natural production declines and production volumes lost due to property sales. In Australia during the three fiscal years ended September 30, 1998, the Company increased its interest in the Comet Ridge coalbed methane project from 30% to 55.75%, participated in the drilling of 19 wells and began selling gas from the project during fiscal 1998. These activities have resulted in proved gas reserves of 122.5 Bcf. At September 30, 1998, total proved oil and gas reserves were 2,388,000 barrels and 132 Bcf, respectively. Using prices in effect at such time and a discount rate of 10% as prescribed by Securities and Exchange Commission rules, total discounted future after tax net cash flows were $46,856,000. Proved oil and gas reserves in the United States decreased by 528,000 barrels and 2.3 Bcf, respectively, from September 30, 1997 reserves calculated using prices then in effect. These decreases are attributable to normal production with minimal replacement of the reserves, sales of producing properties, revisions of previous estimates of reserve volumes and production rates and to lower oil and gas prices as of September 30, 1998, compared to September 30, 1997. The discounted future net cash flow from U.S. properties decreased from $30,251,000 as of September 30, 1997 (using prices as of that date) to $16,176,000 as of September 30, 1998. This decrease was attributable primarily to lower oil and gas prices at September 30, 1998, compared to September 30, 1997, as well as to volume decreases. Proved gas reserves in Australia increased 5.6 Bcf from September 30, 1997, as a result of the Company's acquisition of additional interests in the Comet Ridge project. Under the full cost method of accounting, capitalized oil and gas property costs, less accumulated amortization and related deferred income taxes, may not exceed the sum of the present value of future net revenues from proved reserves and the lower of cost or market value of unproved properties, less related income tax effects. This "ceiling test" must be performed on a quarterly basis. Based on June 30, 1998 oil and gas prices, the Company's full cost pool book value 13 exceeded this ceiling test value by $1,399,000. Accordingly, the book value of oil and gas properties was written down by this amount as of June 30, 1998. See the Consolidated Financial Statements herein. RECENT DEVELOPMENT Subsequent to September 30, 1998, the Company received debt and equity financing of $11,700,000 from Slough Estates USA Inc. ("Slough"), the Company's largest shareholder. This financing is comprised of a loan in the amount of $6,000,000 to be used for development of the Comet Ridge project; $4,000,000 from the issuance of 2,000,000 shares of common stock and an additional loan in the amount of $1,700,000. The commitment for the $6,000,000 loan was made to the Company's Australian subsidiary and the proceeds from this loan will be used to fund the drilling of eight wells and to expand the gathering system on the Comet Ridge project. The loan is evidenced by a five-year note bearing interest at the rate of 10% per annum. The terms of the note also provide that Slough will receive additional payments based upon a royalty of 7% of gross revenues from both the existing and eight proposed wells until the loan is paid in full, after which it will be on the eight new wells for the life of those wells. The Company's share of estimated costs for this development project is approximately $3,300,000. The balance of the proceeds will be available for the Company to extend loans to the remaining working interest owners in the project for their proportionate share of the capital costs of this drilling program. In addition to the promissory note for $6,000,000, the Company will transfer to Slough ten percent of the common stock of the Australian subsidiary. The loan of $1,700,000, together with the $2,700,000 note payable as of September 30, 1998, and an additional $1,100,000 borrowed subsequent to September 30, 1998, are due under the terms of a three-year note for $5,500,000 bearing interest at LIBOR plus 3.5%. The $1,700,000 proceeds from this loan and the $4,000,000 proceeds from the issuance of restricted common stock were used to reduce bank debt by $4,700,000, which brings the current loan balance due the bank to the new borrowing base level of $11,800,000. The remaining $1,000,000 of the proceeds will be used by the Company for working capital. In connection with this debt and equity financing, the Company also issued to Slough warrants to purchase 500,000 shares of the Company's common stock at $3.00 per share, exercisable during a five-year period beginning in December 2000 and ending in December 2005. LIQUIDITY AND CAPITAL RESOURCES For the three years ended September 30, 1998, 1997 and 1996, the Company's primary sources of liquidity have been operating cash flows, debt and equity financing, and sales of non-core producing properties. Cash inflows from operating activities for fiscal 1998, 1997 and 1996 were $525,000, $5,657,000 and $3,955,000, respectively. During this three-year period, the Company has incurred capital expenditures of approximately $29,000,000, of which approximately $18,000,000 was for the acquisition of additional interests in and development of the Comet Ridge project. The Company invested the remaining $11,000,000 in its U.S. properties and other assets, including approximately $4,000,000 in development drilling and $3,500,000 in exploration activities. At September 30, 1998, the Company had cash and cash equivalents of $633,000 as compared to September 30, 1997, when cash and cash equivalents were $3,529,000. At September 30, 1998, the Company had working capital of $1,045,000, a reduction of $336,000 from working capital of $1,381,000 as of September 30, 1997. During fiscal 1998, the Company obtained additional financing by increasing its bank debt from $13,844,000 at September 30, 1997, to $16,500,000 at September 30, 1998, and by securing an additional loan of $400,000 from Slough. Proceeds were also generated from the sale of producing properties and stock issuances in the amounts of $1,456,000 and $190,000, respectively. These proceeds along with cash on hand and operating cash flows were used to fund capital expenditures of $8,033,000. The Company expended approximately $4,950,000 for the acquisition of an additional interest in and funding further development of the Comet Ridge coalbed methane project in Queensland, Australia. The balance of capital expenditures was expended on domestic exploration and development projects and other capital items. The Comet Ridge project expenditures of $4,950,000 in fiscal 1998 included approximately $3,200,000 for the purchase of an additional 5% interest in the project and $1,750,000 in gas gathering and compression costs and other capital expenditures. The Company and its co-venturers in the project completed construction of a gathering system which connects eight wells, through a 17-mile spur line, to a pipeline system serving the Queensland markets. During February 1998, the Company entered into a contract for the sale of gas and began selling approximately 1,000 Mcf per day. As 14 of September 30, 1998, the Company was selling gas at the rate of approximately 2,000 Mcf per day, net to the Company's interest, under short-term contracts. The Company entered into a five-year gas supply contract in September 1998 that calls for the delivery of up to approximately 2,800 Mcf per day, net to the Company's interest. The contract also contemplates the drilling of additional wells in order to produce sufficient sales volumes to satisfy the contract. To that end, the Company plans to use the proceeds from the $6,000,000 project financing loan obtained from Slough to fund its share of the drilling of eight wells and expansion of the gathering system in the Fairview area, and to extend loans to those of its co-venturers requiring them. The Company's pro rata share of minimum expenditure requirements related to the Authority to Prospect granted by the Queensland government, based on current exchange rates, is approximately $350,000, and $725,000 in the years ending October 31, 1999 and 2000, respectively. The Company's interest in the project is now 55.75% of capital costs and 52.50% of operating expenses, and its net revenue interest is 46.34% prior to project payout. Subsequent to project payout, the Company's interest is 45.35% of capital and operating expenses, and its net revenue interest is 39.99%. Domestic capital expenditures of $3,083,000 in fiscal 1998 included exploration and development costs of $2,305,000, non-producing leasehold acquisition costs of $733,000 and other capital expenditures of approximately $45,000. The Company's domestic exploration activities are focused in the Williston Basin of Montana and North Dakota. During the second half of fiscal 1997 and the first half of fiscal 1998, the Company participated in the drilling of seven wells in Montana and North Dakota, of which six were completed as producers. These wells were all exploratory wells based upon three-dimensional ("3-D") seismic data. In April 1998, the Company agreed to transfer to an industry partner 50% of its interest in approximately 31,000 net leasehold acres in its Missouri River project area in Montana in exchange for certain technically defined prospects and proprietary seismic data. Together the companies plan to conduct 3-D seismic surveys over the areas of interest. This project is being re-evaluated based upon currently depressed oil prices and will not be actively pursued until oil prices increase substantially. During fiscal 1997, the Company obtained a loan of $2,300,000 from an affiliate of its largest shareholder. The proceeds were used to acquire an additional 5% capital-bearing interest in the Comet Ridge project. The Company also received proceeds of $1,800,000 from the sale of its interest in an Alabama natural gas liquids ("NGL") fractionating plant, $638,000 from the sale of common stock in United States Exploration Inc. ("UXP") and $39,000 from the sale of miscellaneous oil and gas properties. These sales proceeds, along with cash on hand and cash flows from operating activities, were used to retire $150,000 of bank debt, invest $265,000 in the Alabama NGL fractionating plant(prior to divestiture) and to fund capital expenditures of $9,435,000, of which $5,736,000 was expended on the Comet Ridge project, $849,000 was incurred in domestic exploration, and $2,850,000 was expended on development drilling and other capital items. The Comet Ridge project expenditures of $5,736,000 included approximately $2,300,000 for the acquisition of an additional 5% interest in the project, as well as the Company's share of costs to drill and complete three wells, construct the gas gathering system and compression facilities, and de-water and produce the Fairview area wells. During fiscal 1996, the Company received $6,988,000 from the issuance of common stock, of which approximately $6,091,000 was from the sale of common stock to two institutional investors. Proceeds from other issuances of stock of approximately $897,000 were pursuant to the exercise of warrants and options. The Company sold 75% of its working interest in approximately 30,000 leasehold acres in Divide County, North Dakota for approximately $1,231,000; the Company received $975,000 in cash at closing and had $256,000 applied to its share of capital expenditures in the project. Sales of non-core oil and gas properties generated proceeds of $372,000. In connection with the disposition of convertible preferred stock in UXP on September 30, 1996, the Company received approximately $796,000. The $6,091,000 proceeds from the sale of common stock were used to acquire from an unaffiliated interest holder an additional 15.75% working interest in the Comet Ridge project. The remaining cash proceeds, along with cash on hand and cash flows from operating activities, were used to retire $1,752,000 of bank debt, invest $1,095,000 in the Alabama NGL fractionating plant and fund other capital expenditures of $5,013,000, of which $774,000 was expended on the acquisition of undeveloped acreage in the Williston Basin,$3,270,000 was incurred in development drilling and exploitation projects, including $1,507,000 towards development of the Comet Ridge project, and $969,000 was expended on exploration projects, domestic producing property acquisitions and other capital items. The Company's bank credit agreement (the "agreement") provides a maximum loan facility of $40,000,000 subject to borrowing base limitations described below. The agreement contains provisions for both fixed rate and variable rate borrowings. The Company and its bank entered into an amendment to the loan agreement in February 1998 which 15 provides for a two-tranche revolver with interest at either LIBOR plus 2.5% or the bank's Base Rate on the first $12,000,000 and either LIBOR plus 3.8% or the bank's Base Rate plus 1% on the remainder. The Company may make the selection between LIBOR or the bank's Base Rate, with the LIBOR-based option available for periods not exceeding 90 days. The outstanding loan balance at September 30, 1998, and September 30, 1997, was $16,500,000 and $13,844,000, respectively. The weighted average interest rate was 8.48% as of September 30, 1998, and 7.19% as of September 30, 1997. Upon expiration of the revolver (the "Conversion Date"), the principal balance will convert to a three-year term loan. During the first quarter of fiscal 1998, the Conversion Date was extended by the bank from October 5, 1998, to October 5, 1999. It may be extended again, although the Company has no such assurance from the bank. Certain of the Company's domestic oil and gas properties have been pledged as security for the bank loan, and the Company recently agreed to pledge other unencumbered properties. The maximum borrowing base is determined solely by the bank and is based upon its assessment of the value of the Company's properties. This bank valuation is based upon the bank's assumptions about reserve quantities, oil and gas prices, operating expenses and other assumptions, all of which may change from time to time and which may differ from the Company's assumptions. At September 30, 1997, the borrowing base was $14,500,000. In February 1998, the bank increased the borrowing base by $2,000,000, to $16,500,000. Based on the significant decline in the price of oil and, to a lesser extent, natural gas, the bank reduced the borrowing base to $11,800,000 as of August 31, 1998. Under the terms of the agreement, if the loan balance exceeds the borrowing base, the Company is required to either make a cash payment to the bank equal to or greater than such excess or provide additional collateral to increase the borrowing base by the amount of the deficit. Subsequent to September 30, 1998, the Company used a portion of the proceeds obtained from the financing with its largest shareholder to reduce the bank debt by $4,700,000 to the new borrowing base of $11,800,000. The Company is obligated to pay a commitment fee of 3/8% per annum on the difference between the bank's average outstanding loan balance and the borrowing base. The bank agreement provides that the Company may not pay dividends or incur additional debt without the prior approval of the bank. Significant decreases in oil and gas prices in fiscal 1998 have negatively impacted the Company's cash flows. The Company typically uses hedging techniques to reduce the effects of such price decreases. The Company periodically hedges a portion of its crude oil and gas production through several methods. The Company has in recent years hedged significant portions of its crude oil and to a lesser extent its gas sales through both "swap" agreements and put options traded on the NYMEX. Under swap agreements, the Company usually receives a floor price, but retains 50% of price increases above the floor. Under put options, the Company has the right, but not the obligation, to exercise the option and receive the strike price for the volume of oil or gas subject to the option. During fiscal 1998 the Company hedged an average of 20,000 barrels per month (approximately 56%) of its oil production, at an average price of $18.50 per barrel. The difference between the Company's actual price received at the wellhead and the NYMEX price varies according to location and quality of oil sold. During fiscal 1998, the wellhead price averaged $2.75 per barrel below the NYMEX price. Net receipts (payments) pursuant to the Company's hedging activities for fiscal 1998, 1997 and 1996 were $507,000, ($205,000) and ($387,000), respectively. As of September 30, 1998, the Company had in place a swap agreement covering 5,000 barrels of oil per month for each of October and November 1998 at a floor price of $16.00 per barrel. The Company has not entered into any additional agreements to hedge oil production and none of the Company's gas production is currently hedged for periods subsequent to September 30, 1998. Due to the severe decline in oil prices, and to a lesser extent natural gas prices, the Company's operating cash flows have been negative subsequent to September 30, 1998. In addition to the financing with Slough, the Company may require further financing should these negative cash flows continue for several months. If oil prices increase significantly in the near term, and/or the Company is successful in causing a reduction in operating expenses in the Comet Ridge coalbed methane project, it would be less likely that a further financing would need to be accomplished in the near term. In addition, to the extent the Company's proposed eight-well development drilling program in the Comet Ridge project is successful, management anticipates that additional revenues from gas sales would alleviate the need for additional financing. The Company is reviewing its oil and gas properties to determine whether any may need to be temporarily or permanently shut in and will monitor general and administrative expenses for possible reductions. 16 The Company does not expect to pay significant federal income tax in the near term due to its net operating loss ("NOL") carryforwards. The utilization of these carryforwards reduces the Company's effective federal tax rate from approximately 35% to approximately 2% in years when the Company generates taxable income. The carryforwards total approximately $43 million as of September 30, 1998, and expire over the period from fiscal 1999 through fiscal 2018. These carryforwards would be subjected to a significant annual limitation should there be a change of over 50% in the stock ownership of the Company during any three-year period. The Company has recorded a $21 million asset for the future benefit of its NOL carryforwards and other tax benefits. As of September 30, 1998, this asset was offset by a valuation allowance of $19 million based upon management's projection of realizability of the gross deferred tax asset. Fluctuations in industry conditions and trends warrant periodic management reviews of the recorded valuation allowance to determine if an increase or decrease in such allowance is appropriate. As of June 30, 1998, NYMEX oil and gas prices had decreased approximately 30% and 20%, respectively, from prices as of September 30, 1997. As a result of these price decreases, management revised its assumptions used in projections of taxable income and utilization of net operating loss carryforwards. These revisions, combined with recent net operating tax losses, and the expiration by 2001 of $31 million in total tax net operating loss carryforwards, led management to conclude that the current impact of lower oil and gas prices warranted an increase of $1,618,000 in the deferred tax asset valuation allowance as of June 30,1998, with a corresponding charge to deferred tax expense. YEAR 2000 The year 2000 compliance issue, which is common to most companies, concerns the inability of computer information systems to properly recognize and process date sensitive information as the year 2000 approaches. This could result in errors in information or significant system failures causing disruptions of normal business operations. The Company expects to resolve all issues relating to reprogramming, replacing and testing the affected computer systems prior to December 31, 1999, so that they are year 2000 compliant. To this end, the Company has scheduled an upgrade of its core management information systems during February 1999 so that they will function properly with respect to the year 2000 and beyond. In addition, the Company is currently conducting an inventory, review and assessment of its desktop computers, networks, servers, and software applications to determine if they are year 2000 compliant. Management is also reviewing noninformation technology systems and believes that they are in compliance. The Company will initiate discussions with significant suppliers, purchasers and financial institutions to ensure those parties have addressed year 2000 issues and to assess the extent to which the Company's operations may be impacted should those organizations fail to properly update their computer systems. The Company cannot guarantee that there will not be material adverse effects if these third parties fail to convert their systems in a timely manner and currently believes this to be its most significant risk relating to the year 2000 issue. In order to mitigate the risk of potential failure of third parties to achieve year 2000 compliance, contingency plans are being developed and the Company will survey its significant suppliers and customers to ascertain the status of their conversions and contingency plans. The cost of the year 2000 project is not expected to be material. Funding will be provided by operating cash flows and costs will be expensed as incurred. Time and cost estimates are based on currently available information. Actual results could differ materially from these estimates. RESULTS OF OPERATIONS COMPARISON OF THE FISCAL YEARS ENDED SEPTEMBER 30, 1998 AND 1997 The Company reported a net loss of $6,398,000 in fiscal 1998 versus net income of $472,000 in fiscal 1997. The gross profit from oil and gas sales decreased $3,309,000, or 44%, to $4,127,000 from $7,436,000 due primarily to significantly lower oil prices. Following are detailed comparisons of the components for the respective periods. Operating revenues decreased $3,869,000, or 30%, to $9,082,000 in fiscal 1998 from $12,951,000 in fiscal 1997. Oil volumes decreased 11% to 426,000 barrels in fiscal 1998 from 481,000 barrels in fiscal 1997, resulting in a $1,065,000 revenue decrease. Domestic gas volumes decreased 16% to 1,320,000 Mcf in fiscal 1998 from 1,565,000 Mcf in fiscal 1997, resulting in a $544,000 revenue decrease. These volume decreases are a result of sales of producing properties and natural declines in production. The average oil price decreased 24% to $14.63 in fiscal 1998 from $19.36 in fiscal 17 1997, resulting in a revenue decrease of $2,015,000. The average gas price decreased 23% to $1.72 in fiscal 1998 from $2.22 in fiscal 1997, resulting in a $660,000 revenue decrease. The Company recorded revenues of $452,000 on sales of 371,000 Mcf of gas commencing in February 1998 from the Comet Ridge coalbed methane project in Queensland, Australia. Changes in other revenues accounted for a $37,000 decrease in total revenues. Operating expenses for the fiscal year ended September 30, 1998, decreased $552,000, or 10%, to $4,953,000 from $5,505,000 for fiscal 1997. Operating expenses attributable to the Company's domestic properties decreased $1,028,000, or 19%, to $4,477,000 in fiscal 1998 from $5,505,000 in fiscal 1997. The average lifting cost per equivalent barrel of domestic production decreased 7% to $6.73 in fiscal 1998 from $7.21 in the prior year. These decreases are attributable to sales of marginal producing properties during the first quarter of fiscal 1998 and to a decrease in production taxes resulting from lower oil and gas prices. Operating expenses for fiscal 1998 included $476,000, at a cost of $7.70 per equivalent barrel, related to sales from the Comet Ridge project which commenced in February 1998. The Company believes that operating expenses for the Comet Ridge project on a per-well basis can be reduced and is currently involved in litigation with the operator concerning this and other matters. See Note 8 to the Company's Consolidated Financial Statements. General and administrative expenses increased $267,000, or 18%, to $1,770,000 in fiscal 1998 from $1,503,000 in fiscal 1997, primarily due to an increase in expenses related to the Comet Ridge project. Depreciation, depletion and amortization ("DD&A") expense increased $442,000, or 13%, to $3,974,000 in fiscal 1998 from $3,532,000 in fiscal 1997. The increase is attributable to a higher DD&A rate per barrel resulting primarily from a shorter economic reserve life based on lower oil and gas prices. DD&A expense increases are also the result of the commencement of sales from the Comet Ridge project in Queensland, Australia. Other fiscal 1998 costs and expenses increased compared to fiscal 1997 due to the Company's $1,399,000 write-down of the book value of its oil and gas properties pursuant to full cost ceiling test rules. See Note 3 to the Consolidated Financial Statements. Additionally, deferred financing costs of $422,000 incurred during fiscal 1997 and related to the Comet Ridge project were written off in fiscal 1998. Operating income for fiscal 1997 included a loss from impairment of the Company's investment in the NGL fractionating plant. The Company recorded a non-cash charge to operating income of $538,000 when it wrote down its investment to the selling price of $1,800,000. Interest income decreased $68,000, or 69%, to $31,000 in fiscal 1998 from $99,000 in fiscal 1997. This decrease was due to a decrease in the average balance of cash and cash equivalents during fiscal 1998 as compared to fiscal 1997. Interest expense increased $514,000, or 61%, to $1,354,000 in fiscal 1998 from $840,000 in fiscal 1997. The increase is primarily attributable to an increase in debt and to higher interest rates. See Note 5 to the Company's Consolidated Financial Statements. Other income (expense) for the fiscal year ended September 30, 1998, includes foreign currency exchange losses of $21,000 resulting from an unfavorable exchange rate applied to payments received in Australian currency for coalbed methane gas sales. Included in other income (expense) for the year ended September 30, 1997, was a loss of $258,000 from the disposition of common stock of UXP. Deferred income tax expense increased from $0 in fiscal 1997 to $1,618,000 in fiscal 1998 as a result of an increase in the Company's deferred tax asset valuation allowance. See Note 7 to the Consolidated Financial Statements. The current portion of income tax expense decreased to $0 in fiscal 1998 from a $1,000 expense in fiscal 1997 due to adjustments to expected income tax liabilities. The Company reported equity in the loss of the NGL fractionating plant of $401,000 in fiscal 1997. The Company sold its investment in the plant on September 30, 1997. COMPARISON OF THE FISCAL YEARS ENDED SEPTEMBER 30, 1997 AND 1996 The Company reported net income of $472,000 in fiscal 1997 versus a net loss of $790,000 in fiscal 1996. The gross profit from oil and gas sales increased $1,790,000, or 32%, to $7,436,000 from $5,646,000 due to both higher 18 production volumes and higher realized oil and gas prices. Operating income increased $1,672,000 to $1,873,000 from $201,000. If the $538,000 write-down of the investment in the NGL fractionator were excluded, the increase in operating income would have been $2,210,000. Following are detailed comparisons of the components for the respective periods. Operating revenues increased $1,815,000, or 16%, to $12,951,000 in fiscal 1997 from $11,136,000 in fiscal 1996. Oil volumes increased 2% to 481,000 barrels in fiscal 1997 from 470,000 barrels in fiscal 1996, resulting in a $195,000 revenue increase. Gas volumes increased 1% to 1,565,000 Mcf in fiscal 1997 from 1,550,000 Mcf in fiscal 1996, resulting in a $25,000 revenue increase. These volume increases were a result of new production resulting from exploitation and development drilling projects completed in the fourth quarter of fiscal 1996 and exploration projects in fiscal 1997 that more than offset natural production declines during the year. The average oil price increased 9% to $19.36 in fiscal 1997 from $17.76 in fiscal 1996, resulting in a revenue increase of $770,000. The average gas price increased 32% to $2.22 in fiscal 1997 from $1.68 in fiscal 1996, resulting in an $845,000 revenue increase. Changes in other revenues accounted for a $20,000 decrease in total revenues. Operating expenses remained relatively flat, decreasing $42,000, or 1%, to $5,505,000 in fiscal 1997 from $5,547,000 in fiscal 1996. The Company's average lifting cost per equivalent barrel produced also decreased 1% to $7.21 in fiscal 1997 from $7.30 in fiscal 1996. General and administrative expenses decreased $158,000, or 10%, to $1,503,000 in fiscal 1997 from $1,661,000 in fiscal 1996, primarily due to a decrease in payroll costs. Salaries expense in fiscal 1996 included a $324,000 charge associated with the exercise of warrants by a former officer of the Company. DD&A expense decreased $195,000, or 5%, to $3,532,000 in fiscal 1997 from $3,727,000 in fiscal 1996. The decrease was attributable to a lower DD&A rate per equivalent barrel. Operating income for fiscal 1997 includes a loss from impairment of the Company's investment in the NGL fractionating plant. The Company recorded a non-cash charge to operating income of $538,000 when it wrote down its investment to the selling price of $1,800,000. No such losses or other write-downs were reported in fiscal 1996. Interest income decreased $117,000, or 54%, to $99,000 in fiscal 1997 from $216,000 in fiscal 1996. This decrease was due to a decrease in the average balance of cash and cash equivalents during fiscal 1997 as compared to fiscal 1996. Dividend income decreased to $0 during fiscal 1997, from $89,000 in the fiscal 1996. Dividend income was accrued during fiscal 1996 on 354,000 shares of convertible preferred stock of UXP and received in the form of common stock during fiscal 1997. The convertible preferred stock was exchanged for common stock of UXP on September 30, 1996. All of the common stock of UXP was sold during fiscal 1997. Interest expense decreased $91,000, or 10%, to $840,000 in fiscal 1997 from $931,000 in fiscal 1996. When capitalized interest is included, interest expense increased by $122,000. The increase was primarily attributable to an increase in debt and to higher interest rates. Other income (expense) for the year ended September 30, 1997, includes a loss of $258,000 from the disposition of common stock of UXP. Included in other income (expense) for fiscal 1996 was a loss of $273,000 on the disposition of preferred stock of UXP. Research and development expense for oil spill cleanup research decreased to $0 in fiscal 1997, from $23,000 in fiscal 1996. The Company met its contractual funding commitment in the fourth quarter of fiscal 1994, but made voluntary payments for third party consulting services during fiscal 1995 and 1996. Income tax expense increased $7,000 to an expense of $1,000 in fiscal 1997 from a benefit of $6,000 in fiscal 1996. Both the benefit in fiscal 1996 and the expense in fiscal 1997 were due to adjustments for prior period taxes. The equity interest in the net loss of the NGL fractionator increased $326,000 to a loss of $401,000 in fiscal 1997 from a loss of $75,000 in fiscal 1996. The increase in the loss was attributable to a lower profit margin on NGL products, 19 production interruption caused by two lightning strikes on the plant and an increase in depreciation expense and other expenses. The Company sold its entire interest in the NGL fractionator on September 30, 1997. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The Company's Consolidated Financial Statements and supplementary financial data follow page 25 and are incorporated herein by reference. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES None. PART III The Company hereby undertakes on or before 120 days after September 30, 1998, to file with the Commission a Definitive Proxy Statement pursuant to Regulation 14A with respect to the Company's Annual Meeting of Shareholders, which Proxy Statement will contain the information required by Part III. Such information is incorporated herein by reference. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) The following documents are filed as a part of the report: For a list of financial statements and financial statement schedules, see "Index to Consolidated Financial Statements" which is part of the Financial Statements and Supplementary Data which follow page 25 and are incorporated herein by reference. (b) During the last quarter of the Company's fiscal year ended September 30, 1998, the Company filed no reports on Form 8- K. (c) Exhibits: For a list of exhibits, see "Exhibits" which follows page 21 and is incorporated herein by reference. 20 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. TIPPERARY CORPORATION Date December 22, 1998 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 Securities Exchange Act of 1934, 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 President, Chief Executive Officer December 22, 1998 - ------------------------- and Chairman of the Board of Directors David L. Bradshaw /s/ Lisa S. Wilson Chief Financial Officer December 22, 1998 - ------------------------- Lisa S. Wilson /s/ Kenneth L. Ancell Director December 22, 1998 - ------------------------- Kenneth L. Ancell /s/ Eugene I. Davis Director December 22, 1998 - ------------------------- Eugene I. Davis /s/ Douglas Kramer Director December 22, 1998 - ------------------------- Douglas Kramer /s/ Marshall D. Lees Director December 22, 1998 - ------------------------- Marshall D. Lees
21 EXHIBITS
Number Description - ------ ----------- 3.9 Restated Articles of Incorporation of Tipperary Corporation adopted May 6, 1993, 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. 3.10 Restated Corporate Bylaws of Tipperary Corporation adopted June 28, 1993, 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. 4.37 Second Amendment to Credit Agreement dated September 27, 1991, by and between Tipperary Petroleum Company and Central Bank, National Association, filed as Exhibit 4.37 to Form 10-K dated September 30, 1991, and incorporated herein by reference. 4.39 Revolving Credit and Term Loan Agreement dated March 30, 1992, by and between Central Bank, N.A. and Tipperary Petroleum Company, Tipperary Corporation and Tipperary Oil & Gas Corporation, filed as Exhibit 4.39 to Form 10- Q dated March 31, 1992, and incorporated herein by reference. 4.40 Third Amended and Restated Mortgage, Deed of Trust, Assignment of Proceeds, Security Agreement and Financing Statement from Tipperary Petroleum Company and Tipperary Oil and Gas Corporation to Central Bank, N.A. dated March 30, 1992, filed as Exhibit 4.40 to Form 10-Q dated March 31, 1992, and incorporated herein by reference. 4.41 Revolving Note dated March 30, 1992, in the amount of $40,000,000 between Tipperary Petroleum Company, Tipperary Corporation and Tipperary Oil and Gas Corporation (makers) and Central Bank, N.A., filed as Exhibit 4.41 to Form 10-Q dated March 31, 1992, and incorporated herein by reference. 4.42 Term Note dated March 30, 1992, in the amount of $40,000,000 between Tipperary Petroleum Company, Tipperary Corporation and Tipperary Oil and Gas Corporation (makers) and Central Bank, N.A., filed as Exhibit 4.42 to Form 10-Q dated March 31, 1992, and incorporated herein by reference. 4.43 Amendment of Revolving Credit and Term Loan Agreement dated September 30, 1993, by and among Tipperary Corporation, Tipperary Oil & Gas Corporation and Colorado National Bank, filed as Exhibit 4.43 to Form 10-K dated September 30, 1993, and incorporated herein by reference. 4.44 Second Amendment of Revolving Credit and Term Loan Agreement dated March 31, 1994, by and among Colorado National Bank f/k/a/ Central Bank, N.A., Tipperary Corporation and Tipperary Oil & Gas Corporation, filed as Exhibit 4.44 to Form 10-Q dated March 31, 1994, and incorporated herein by reference. 4.45 Negative Pledge Agreement dated March 31, 1994, by and among Colorado National Bank, Tipperary Corporation and Tipperary Oil & Gas Corporation, filed as Exhibit 4.45 to Form 10-Q dated March 31, 1994, and incorporated herein by reference. 4.46 Third Amendment of Revolving Credit and Term Loan Agreement dated March 31, 1995, by and among Colorado National Bank f/k/a Central Bank, N.A., Tipperary Corporation and Tipperary Oil & Gas Corporation filed as Exhibit 4.46 to Form 10-Q dated March 31, 1995, and incorporated herein by reference. 4.47 Fourth Amendment of Revolving Credit and Term Loan Agreement dated as of March 31, 1996, by and among Tipperary Corporation, Tipperary Oil & Gas Corporation, and Colorado National Bank f/k/a
22 EXHIBITS
Number Description - ------ ----------- Central Bank, N.A., filed as Exhibit 4.47 to Form 10-Q dated March 31, 1996, and incorporated herein by reference. 4.48 Promissory Note dated December 20, 1996, in the amount of $2,300,000 between Registrant and Slough Parks Incorporated, filed as Exhibit 4.48 to Form 10-Q dated December 31, 1996, and incorporated herein by reference. 4.49 Subordination Agreement dated December 20, 1996, by and between Slough Parks Incorporated and Colorado National Bank, filed as Exhibit 4.49 to Form 10-Q dated December 31, 1996, and incorporated herein by reference. 4.50 Fifth Amendment of Revolving Credit and Term Loan Agreement dated March 3, 1997, by and among Tipperary Corporation, Tipperary Oil & Gas Corporation, and Colorado National Bank, a national banking association, filed as Exhibit 4.50 to Form 10-Q dated March 31, 1997, and incorporated herein by reference. 4.51 Addendum to Mortgage - Collateral Real Estate Mortgage dated as of May 27, 1997, executed by Colorado National Bank, Tipperary Corporation and Tipperary Oil & Gas Corporation filed as Exhibit 4.51 to Form 10-Q dated June 30, 1997, and incorporated herein by reference. 4.52 Amendment to Promissory Note, dated December 15, 1997, between Registrant and Slough Parks Incorporated, filed as Exhibit 4.52 to Form 10-Q dated December 31, 1997, and incorporated herein by reference. 4.53 Promissory Note dated October 31, 1997, in the amount of $885,000 between Registrant and Amerind Oil Company, Ltd., filed as Exhibit 4.53 to Form 10-Q dated December 31, 1997, and incorporated herein by reference. 4.54 Sixth Amendment of Revolving Credit and Term Loan Agreement by and among Tipperary Corporation, Tipperary Oil & Gas Corporation, and U.S. Bank, N.A., f/k/a Colorado National Bank dated February 13, 1998, filed as Exhibit 4.54 to Form 10-Q dated March 31, 1998, and incorporated herein by reference. 4.55 Amendment of Subordination Agreement and Consent of Subordinating Party between Slough Parks Incorporated, and U.S. Bank, N.A., f/k/a Colorado National Bank, dated February 13, 1998, filed as Exhibit 4.55 to Form 10-Q dated March 31, 1998, and incorporated herein by reference. 4.56 Agreement between Tipperary Oil & Gas Corporation as Maker and Amerind Oil Company, Ltd., as Payee to extend maturity date of Promissory Note, filed as Exhibit 4.56 to Form 10-Q dated March 31, 1998, and incorporated herein by reference. 4.57 Promissory Note dated August 31, 1998, in the amount of $1,000,000 between Registrant and Slough Estates USA Inc., filed herewith. 10.13 Warrant to purchase the Registrant's common stock dated October 29, 1990, issued to James A. McAuley, filed as Exhibit 10.13 to Form 10-K dated September 30, 1990, and incorporated herein by reference. 10.36 Warrant to Purchase the Registrant's common stock dated April 26, 1994, issued to Eugene I. Davis, filed as Exhibit 10.36 to Form 10-Q dated March 31, 1994, and incorporated herein by reference.
23 EXHIBITS
Number Description - ------ ----------- 10.37 United States Exploration, Inc. 1994 Series A Convertible Preferred Stock and 1994 Series B Convertible Preferred Stock Purchase Agreement by United States Exploration, Inc. and Tipperary Corporation, dated July 18, 1994, and Exhibits filed as Exhibit 10.37 to Form 10-Q dated June 30, 1994, and incorporated herein by reference. 10.39 Amended Warrant to Purchase the Registrant's common stock dated February 1, 1995, issued to James A. McAuley filed as Exhibit 10.39 to Form 10-Q dated March 31, 1995, and incorporated herein by reference. 10.40 Warrant to Purchase the Registrant's common stock dated April 1, 1996, issued to David L. Bradshaw, filed as Exhibit 10.40 to Form 10-K dated September 30, 1996, and incorporated herein by reference. 10.41 Warrant to Purchase the Registrant's common stock dated July 11, 1996, issued to Kenneth L. Ancell, filed as Exhibit 10.41 to Form 10-K dated September 30, 1996, and incorporated herein by reference. 10.42 Agreement for Conversion of Preferred Stock, Sale of Common Stock and Settlement of Preferred Stock Dividends, by and among the Registrant, United States Exploration, Inc., Dale Jensen, Jerome N. Fenna and Betty A. Fenna dated September 30, 1996, filed as Exhibit 10.42 to Form 10-K dated September 30, 1996, and incorporated herein by reference. 10.45 Divide Exploration Agreement entered into August 22, 1996, between Tipperary Oil & Gas Corporation and Lyco Energy Corporation, filed as Exhibit 10.45 to Form 10-K dated September 30, 1996, and incorporated herein by reference. 10.46 Purchase and Sale Agreement between Cavell Energy (U.S.) Corporation and Tipperary Oil & Gas Corporation dated September 19, 1996, filed as Exhibit 10.46 to Form 10-K dated September 30, 1996, and incorporated herein by reference. 10.47 Agreement concerning the addition of Cavell Energy (U.S.) Corporation as a party to the Exploration Agreement and Operating Agreement and certain amendments to such agreements by and among Tipperary Oil & Gas Corporation, Cavell Energy (U.S.) Corporation and Lyco Energy Corporation, dated September 19, 1996, filed as Exhibit 10.47 to Form 10-K dated September 30, 1996, and incorporated herein by reference. 10.48 Purchase and Sale Agreement dated June 28, 1996, between Tipperary Oil & Gas Corporation and Clovelly Oil Co., Inc., filed as Exhibit 10.48 to Form 10-K dated September 30, 1996, and incorporated herein by reference. 10.49 Purchase and Sale Agreement dated January 29, 1997, between NationsBank of Texas, N.A., as Trustee for Trusts #1190 and #1191 ("Seller") and Tipperary Oil & Gas Corporation ("Buyer"), filed as Exhibit 10.49 to Form 10-Q dated December 31, 1996, and incorporated herein by reference. 10.50 Purchase and Sale Agreement dated January 29, 1997, between NationsBank of Texas, N.A., as Trustee for Trusts #1362, #1363 and #1364 ("Seller") and Tipperary Oil & Gas Corporation ("Buyer"), filed as Exhibit 10.50 to Form 10-Q dated December 31, 1996, and incorporated herein by reference. 10.51 Tipperary Corporation 1997 Long-Term Incentive Plan filed as Exhibit A to the Registrant's Proxy Statement for its Annual Meeting of Shareholders held on January 28, 1997, filed as Exhibit 10.51 to Form 10-Q dated December 31, 1996, and incorporated herein by reference.
24 EXHIBITS
Number Description - ------ ----------- 10.52 Warrant to Purchase the Registrant's common stock dated August 26, 1997, issued to David L. Bradshaw, filed as Exhibit 10.52 to Form 10-Q dated December 31, 1996, and incorporated herein by reference. 10.53 Warrant to Purchase the Registrant's common stock dated August 26, 1997, issued to Kenneth L. Ancell, filed as Exhibit 10.53 to Form 10-K dated September 30, 1997, and incorporated herein by reference. 10.54 Warrant to Purchase the Registrant's common stock dated August 26, 1997, issued to Eugene I. Davis, filed as Exhibit 10.54 to Form 10-K dated September 30, 1997, and incorporated herein by reference. 10.55 Warrant to Purchase the Registrant's common stock dated August 26, 1997, issued to Marshall D. Lees, filed as Exhibit 10.55 to Form 10-K dated September 30, 1997, and incorporated herein by reference. 10.56 Stock Purchase Agreement dated September 30, 1997 by and among Tipperary Corporation, Milmac Operating Company and James A. McAuley, filed as Exhibit 10.56 to Form 10- K dated September 30, 1997, and incorporated herein by reference. 10.57 Purchase and Sale Agreement dated October 31, 1997, effective as of the 1st day of January, 1997, by and between Amerind Oil Company, Ltd. as Seller and Tipperary Oil & Gas Corporation, as Buyer, filed as Exhibit 10.57 to Form 10-K dated September 30, 1997, and incorporated herein by reference. 11.1 Calculation of per share earnings, filed herewith. 21.1 List of subsidiaries, filed herewith. 23.1 Consent of PricewaterhouseCoopers LLP, filed herewith. 27 Financial Data Schedule 99.1 "Risk Factors" discussion from Registration Statement on Form S-8, SEC File No. 333-40589, pages 5 through 8, filed herewith.
25 TIPPERARY CORPORATION AND SUBSIDIARIES Index to Consolidated Financial Statements Report of Independent Accountants F-2 Consolidated Balance Sheet September 30, 1998 and 1997 F-3 Consolidated Statement of Operations Years ended September 30, 1998, 1997 and 1996 F-4 Consolidated Statement of Stockholders' Equity Years ended September 30, 1998, 1997 and 1996 F-5 Consolidated Statement of Cash Flows Years ended September 30, 1998, 1997 and 1996 F-6 Notes to Consolidated Financial Statements F-7
F-1 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Shareholders of Tipperary Corporation In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Tipperary Corporation and its subsidiaries at September 30, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 1998, in conformity with generally accepted accounting principles. 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 generally accepted auditing standards which 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 the opinion expressed above. /s/ PricewaterhouseCoopers LLP PRICEWATERHOUSECOOPERS LLP Denver, Colorado December 22, 1998 F-2 TIPPERARY CORPORATION AND SUBSIDIARIES Consolidated Balance Sheet September 30, 1998 and 1997 (in thousands)
1998 1997 ---------- -------- ASSETS Current assets: Cash and cash equivalents $ 633 $ 3,529 Receivables 1,408 1,966 Inventory 218 197 Current portion of deferred income taxes, net - 229 Other current assets 66 123 ---------- --------- Total current assets 2,325 6,044 ---------- --------- Property, plant and equipment, at cost: Oil and gas properties, full cost method 136,647 131,578 Other property and equipment 2,571 2,476 ---------- --------- 139,218 134,054 Less accumulated depreciation, depletion and amortization (92,626) (88,708) ---------- --------- Property, plant and equipment, net 46,592 45,346 ---------- --------- Noncurrent portion of deferred income taxes, net 1,573 2,962 Other noncurrent assets 270 643 ---------- --------- $ 50,760 $ 54,995 ========== ========= LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Note payable - related party $ - $ 2,300 Accounts payable 680 1,275 Advances from joint owners - 468 Accrued liabilities 341 288 Production taxes payable 103 159 Royalties payable 156 173 ---------- --------- Total current liabilities 1,280 4,663 ---------- --------- Long-term debt 16,500 13,844 Long-term note payable - related party 2,700 - Commitments and contingencies (Note 8) Stockholders' equity Common stock; par value $.02; 20,000,000 shares authorized; 13,161,755 issued and 13,133,955 outstanding in 1998; 13,078,071 issued and 13,050,271 outstanding in 1997 263 262 Capital in excess of par value 105,564 105,375 Accumulated deficit (75,476) (69,078) Treasury stock, at cost; 27,800 shares (71) (71) ---------- --------- Total stockholders' equity 30,280 36,488 ---------- --------- $ 50,760 $ 54,995 ========== =========
See accompanying notes to consolidated financial statements. F-3 TIPPERARY CORPORATION AND SUBSIDIARIES Consolidated Statement of Operations Years ended September 30, 1998, 1997 and 1996 (in thousands, except per share data)
1998 1997 1996 ---------- --------- ---------- Revenues $ 9,082 $ 12,951 $ 11,136 Costs and expenses: Operating 4,953 5,505 5,547 General and administrative 1,770 1,503 1,661 Depreciation, depletion and amortization 3,974 3,532 3,727 Write-down of oil and gas properties 1,399 - - Write-down of deferred financing costs 422 - - Loss on sale of investment in NGL fractionating plant - 538 - ---------- --------- ---------- Total costs and expenses 12,518 11,078 10,935 ---------- --------- ---------- Operating income (loss) (3,436) 1,873 201 ---------- --------- ---------- Other income (expense): Interest income 31 99 216 Dividend income - - 89 Interest expense (1,354) (840) (931) Loss on disposition of stock - (258) (273) Research and development expense - - (23) Foreign currency exchange loss (21) - - ---------- --------- ---------- Total other expense (1,344) (999) (922) ---------- --------- ---------- Income (loss) before income taxes (4,780) 874 (721) ---------- --------- ---------- Current income tax benefit (expense) - (1) 6 Deferred income tax expense (1,618) - - ---------- --------- ---------- Income (loss) before equity in loss of NGL fractionating plant (6,398) 873 (715) Equity in loss of NGL fractionating plant - (401) (75) ---------- --------- ---------- Net income (loss) $ (6,398) $ 472 $ (790) ========== ========= ========= Net income (loss) per share - basic and diluted $ (.49) $ .04 $ (.07) ========== ========= ========= Weighted average shares outstanding 13,118 13,050 11,807 ========== ========= =========
See accompanying notes to consolidated financial statements. F-4 TIPPERARY CORPORATION AND SUBSIDIARIES Consolidated Statement of Stockholders' Equity Years ended September 30, 1998, 1997 and 1996 (in thousands)
Common Stock Capital in Treasury Stock ----------------- excess of Accumulated ---------------- Shares Amount par value Deficit Shares Amount Total ------ ------- --------- ------------ ------ ------- ----- Balance September 30, 1995 11,210 $ 225 $ 98,424 $(68,760) 28 $ (71) $ 29,818 Net loss -- -- -- (790) -- -- (790) Common stock issuance 1,400 28 6,063 -- -- -- 6,091 Exercise of stock options and warrants 440 9 888 -- -- -- 897 ------ ----- -------- -------- ---- ----- -------- Balance September 30, 1996 13,050 262 105,375 (69,550) 28 (71) 36,016 Net income -- -- -- 472 -- -- 472 ------ ----- -------- -------- ---- ----- -------- Balance September 30, 1997 13,050 262 105,375 (69,078) 28 (71) 36,488 Net loss -- -- -- (6,398) -- -- (6,398) Exercise of stock options and warrants 84 1 189 -- -- -- 190 ------ ----- -------- -------- ---- ----- -------- Balance September 30, 1998 13,134 $ 263 $105,564 $(75,476) 28 $ (71) $ 30,280 ====== ===== ======== ======== ==== ===== ========
See accompanying notes to consolidated financial statements. F-5 TIPPERARY CORPORATION AND SUBSIDIARIES Consolidated Statement of Cash Flows Years ended September 30, 1998, 1997 and 1996 (in thousands)
1998 1997 1996 ---- ---- ---- Cash flows from operating activities: Net income (loss) $ (6,398) $ 472 $ (790) -------- -------- -------- Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion and amortization 3,974 3,532 3,727 Write-down of oil and gas properties 1,399 -- -- Write-down of deferred financing costs 422 -- -- Loss on sale of investment in NGL fractionating plant -- 538 -- Equity in loss of NGL fractionating plant -- 401 75 Loss on disposition of stock -- 258 273 Deferred income tax expense 1,618 -- -- Change in assets and liabilities: Decrease in receivables 558 188 201 (Increase) in inventory (21) (7) -- Decrease in other current assets 57 -- 53 Increase (decrease) in accounts payable and accrued liabilities (542) (191) 743 Increase (decrease) in advances from joint owners (468) 468 -- Increase (decrease) in royalties payable (17) 25 (64) (Decrease) in production taxes payable (56) (27) (71) Other (1) -- (192) -------- -------- -------- 6,923 5,185 4,745 -------- -------- -------- Net cash provided by operating activities 525 5,657 3,955 -------- -------- -------- Cash flows from investing activities: Proceeds from sale of assets 1,456 39 1,603 Proceeds from sale of common stock -- 638 796 Proceeds from sale of investment in NGL fractionating plant -- 1,800 -- Capital expenditures (8,033) (9,435) (11,113) Investment in NGL fractionating plant -- (265) (1,095) -------- -------- -------- Net cash used in investing activities (6,577) (7,223) (9,809) -------- -------- -------- Cash flows from financing activities: Proceeds from borrowing 3,056 2,300 -- Principal repayments -- (150) (1,752) Proceeds from issuance of stock 190 -- 6,988 Payments for debt and equity financing (90) (630) -- -------- -------- -------- Net cash provided by financing 3,156 1,520 5,236 -------- -------- -------- Net decrease in cash and cash equivalents (2,896) (46) (618) Cash and cash equivalents at beginning of year 3,529 3,575 4,193 -------- -------- -------- Cash and cash equivalents at end of year $ 633 $ 3,529 $ 3,575 ======== ======== ======== Supplemental disclosure of cash flow information: Cash paid during the period for: Interest $ 1,431 $ 831 $ 942 Income taxes $ -- $ 1 $ 23
See accompanying notes to consolidated financial statements. F-6 TIPPERARY CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements September 30, 1998, 1997 and 1996 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 crude oil and natural gas. The Company was organized as a Texas corporation in January 1967. The Company entered the oil and gas business in 1969 when it acquired its Permian Basin oil and gas properties located in Lea County, New Mexico. The Company has since expanded its activities to other areas of the United States, predominantly the Rocky Mountain and Mid-Continent areas, and also to Queensland, Australia, where it is involved in exploration for and development and production of coalbed methane gas. USE OF ESTIMATES AND SIGNIFICANT RISKS The preparation of consolidated financial statements in conformity with generally accepted accounting principles 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 oil and gas reserves, fair value of financial instruments, future cash flows associated with assets and useful lives for depreciation, depletion and amortization. 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 crude oil and 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. PARTNERSHIPS AND OTHER EQUITY INVESTMENTS The consolidated financial statements include the Company's proportionate share of the assets, liabilities, revenues and expenses of its oil and gas partnership interests. The Company's investments in limited liability companies over which it exercises significant influence have been accounted for under the equity method. CASH AND CASH EQUIVALENTS The Company considers all highly liquid investments purchased with a maturity of three months or less to be cash equivalents. CONCENTRATIONS OF CREDIT RISK The Company maintains demand deposit accounts with one bank in Denver, Colorado and one bank in Brisbane, Queensland, Australia and invests cash in bank money market accounts and other money market funds which the Company believes have minimal risk of loss. As an operator of jointly owned oil and gas properties, the Company sells oil and gas production to numerous oil and gas purchasers and pays vendors for oil and gas services. The risk of non-payment by the purchasers is considered minimal and the Company does not obtain collateral for sales to them. Joint interest receivables are subject to collection under the terms of operating agreements which provide lien rights. Although the Company normally considers the risk of loss likewise to be minimal, the recent decline in oil and gas prices may cause some oil and gas companies liquidity problems and thereby increase such risk. F-7 TIPPERARY CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements FAIR VALUE OF FINANCIAL INSTRUMENTS CASH AND CASH EQUIVALENTS, RECEIVABLES AND CURRENT LIABILITIES The carrying amount approximates fair value because of the short maturity of these instruments. LONG-TERM DEBT At September 30, 1998 and 1997, based on rates available for similar types of debt, the fair value of long-term debt was not materially different from its carrying amount . INVENTORY Inventory is composed of tubular goods and supplies and is valued at the lower of average cost or market. 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 and depletion. Depletable costs also include estimates of future development costs of proved reserves. Costs related to undeveloped oil and gas properties may be excluded from depletable costs until such properties are evaluated as either proved or unproved. The net capitalized costs are subject to a ceiling limitation. See Note 3. Gains or losses upon disposition of oil and gas properties are treated as adjustments to capitalized costs, unless the disposition represents a significant portion of the Company's proved reserves. A separate cost center is maintained for expenditures applicable to each country in which the Company conducts exploration and/or production activities. Repairs and maintenance are expensed; renewals and betterments are capitalized. Certain indirect costs, including general and administrative expense, have been capitalized to property, plant and equipment. Interest costs for the construction of certain long term assets and for the investment in significant unproved properties and development projects are capitalized and amortized over the related asset's estimated useful life. No interest was capitalized in fiscal 1998, however, the Company did capitalize $297,000 and $84,000 of interest costs in fiscal 1997, and 1996, respectively. 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 gain or loss is recognized. DEPRECIATION, DEPLETION AND AMORTIZATION Depreciation and depletion of oil and gas properties is provided using the units-of-production method computed using proved oil and gas reserves. Depreciation and amortization of other property, plant and equipment and other assets is provided using the straight-line method computed over estimated useful lives ranging from three to fifteen years. INCOME TAXES Deferred income taxes are provided on the difference between the tax basis of an asset or liability and its reported amount in the financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. F-8 TIPPERARY CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements CRUDE OIL AND NATURAL GAS HEDGING The Company periodically hedges a portion of its crude oil and natural gas production through several methods. In cases where direct investments are made in futures contracts, gains or losses on the hedges are deferred and recognized in income as the hedged commodity is produced. The Company has in recent years hedged significant portions of its crude oil and gas sales primarily through both "swap" agreements and put options with financial institutions based upon prices quoted by the New York Mercantile Exchange ("NYMEX"). Under swap agreements, the Company usually receives a floor price but retains 50% of price increases above the floor. Under put options, the Company has the right, but not the obligation, to exercise the option and receive the strike price for the volume of oil subject to the option. During fiscal 1998, the Company hedged an average of 20,000 barrels per month (approximately 56%) of its oil production at an average price of $18.50 per barrel. The Company's actual price received at the wellhead averaged $2.75 per barrel below NYMEX prices during fiscal 1998, due to differences in location and quality of oil sold. Net receipts (payments) pursuant to the Company's hedging activities for fiscal 1998, 1997 and 1996 were $507,000, ($205,000) and ($387,000), respectively. As of September 30, 1998, the Company had in place a swap agreement covering 5,000 barrels of oil production for each of October and November 1998 at $16.00 per barrel. The Company has not entered into any new agreements to hedge oil production and none of the Company's gas production is currently hedged for periods subsequent to September 30, 1998. EARNINGS (LOSS) PER SHARE The Company adopted Statement of Financial Accounting Standards No. 128, "Earnings per Share" ("SFAS 128"), effective October 1, 1997. SFAS 128 simplifies the computation of earnings per share by replacing the primary and fully diluted presentations with new "basic" and "diluted" disclosures. In accordance with the requirements of SFAS 128, basic earnings per share is computed using the weighted average number of shares outstanding. Diluted earnings per share reflects the potential dilution that would occur if options and warrants were exercised using the average market price for the Company's stock for the period. Earnings (loss) per share as previously reported did not change due to the new statement. FOREIGN CURRENCY The Company considers the functional currency of its Australian subsidiary to be the U.S. dollar. Exchange gains and losses arising from remeasurement of monetary assets and liabilities that are not denominated in the functional currency are included in the Statement of Operations as an adjustment to net income. STOCK-BASED COMPENSATION Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation," encourages, but does not require, companies to record the compensation cost for stock-based employee compensation plans at fair value. 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." 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. DEFERRED FINANCING COSTS Certain legal and consulting costs associated with obtaining new financing have been capitalized. These expenses, as they relate to raising capital through the issuance of stock, are accounted for as a reduction of the related proceeds. The expenses attributable to raising debt financing are amortized over the term of the related credit agreement. F-9 TIPPERARY CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements SIGNIFICANT CUSTOMERS The Company had sales in excess of 10% of total revenues to three unaffiliated oil and gas customers during fiscal 1998 totaling 43%, three unaffiliated oil and gas customers during fiscal 1997 totaling 41%, and three unaffiliated oil and gas customers during fiscal 1996 totaling 42%. The Company does not believe that the loss of any existing purchaser would have a material adverse impact on its ability to sell its production to another purchaser at similar prices. IMPACT OF NEW ACCOUNTING PRONOUNCEMENTS In June 1997, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 130, "Reporting Comprehensive Income" ("SFAS 130"), which establishes standards for reporting and display of comprehensive income and its components in a full set of general purpose financial statements. The Company will adopt SFAS 130 effective October 1, 1998, and does not believe that it will have a material impact on its financial statements. In June 1997, the FASB issued Statement of Financial Accounting Standards No. 131, "Disclosures about Segments of an Enterprise and Related Information" ("SFAS 131"), which establishes standards for disclosures regarding operating segments in both interim and annual financial statements issued to shareholders and requires related disclosures about products and services, geographic areas and major customers. The Company will adopt SFAS 131, effective October 1, 1998, and does not believe that it will have a material impact on its financial statements. In June 1998, the FASB issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"). This statement is effective for all fiscal quarters of fiscal years beginning after June 15, 1999, and will be adopted by the Company effective October 1, 1999. SFAS 133 requires companies to report the fair-market value of derivatives on the balance sheet and record in income or other comprehensive income, as appropriate, any changes in the fair value of the derivative. The Company does not believe that adoption of this Standard will have a material impact on its financial statements. NOTE 2 - RELATED PARTY TRANSACTIONS Subsequent to September 30, 1998, the Company received debt and equity financing of $11,700,000 from Slough Estates USA Inc. ("Slough"), the Company's largest shareholder. This financing is comprised of a loan in the amount of $6,000,000 to be used for development of the Comet Ridge project; $4,000,000 from the issuance of 2,000,000 shares of common stock; and an additional loan in the amount of $1,700,000. The commitment for the $6,000,000 loan was made to the Company's Australian subsidiary and the proceeds from this loan will be used to fund the drilling of eight wells and to expand the gathering system on the Comet Ridge project. The loan is evidenced by a five-year note bearing interest at the rate of 10% per annum. The terms of the note also provide that Slough will receive additional payments based upon a royalty of 7% of gross revenues from both the existing and eight proposed wells until the loan is paid in full, after which it will be on the eight new wells for the life of those wells. The Company's share of estimated costs for this development project is approximately $3,300,000. The balance of the proceeds will be available for the Company to extend loans to the remaining working interest owners in the project for their proportionate share of the capital costs of this drilling program. In addition to the promissory note for $6,000,000, the Company will transfer to Slough ten percent of the common stock of the Australian subsidiary. The loan of $1,700,000, together with the $2,700,000 note payable as of September 30, 1998, and an additional $1,100,000 borrowed subsequent to September 30, 1998, are due under the terms of a three-year note for $5,500,000. The $1,700,000 proceeds from this loan and the $4,000,000 proceeds from the issuance of restricted common stock were used to reduce bank debt by $4,700,000 which brings the current loan balance due the bank to the new borrowing base level of $11,800,000. The remaining $1,000,000 of the proceeds will be used by the Company for working capital. In connection with this debt and equity financing, the Company issued to Slough warrants to purchase 500,000 shares of the Company's common stock at $3.00 per share, exercisable during a five-year period beginning in December 2000 and F-10 ending in December 2005. Total interest paid to Slough during fiscal 1998 and 1997 was $197,316 and $133,904, respectively. NOTE 3 - OIL AND GAS FULL COST POOLS UNITED STATES The Company's domestic full cost pool includes capital costs incurred in domestic property acquisition, exploration and development. The total book value of the United States full cost pool as of September 30, 1998, was $22,566,000. Included in this total are $3,608,000 of acquisition costs attributable to nonproducing oil and gas leases, primarily in the WillistonBasin, that have been excluded from depletable costs pending further evaluation. At September 30, 1998, total domestic proved oil and gas reserves were 2,388,000 barrels and 9 Bcf, respectively. Using prices in effect at such time and a discount rate of 10% as prescribed by Securities and Exchange Commission rules, total discounted after tax net revenues were $16,176,000. Proved oil and gas reserves decreased by 528,000 barrels and 2.3 Bcf, respectively, from September 30, 1997, reserves calculated using prices then in effect. The discounted future net revenues from U.S. properties decreased $14,075,000 from the discounted future net revenues from U.S. properties at September 30, 1997. The decrease in reserve volumes is attributable to the sale of the Company's interest in non-core oil and gas producing properties in 1998, normal production without replacement of reserves, revisions of previous estimates of reserve volumes and rates of production and to lower oil and gas prices as of September 30, 1998. The decrease in discounted future net revenues was attributable to these volume decreases and to lower prices at September 30, 1998, as compared to September 30, 1997. Under the full cost method of accounting, capitalized oil and gas property costs, less accumulated amortization and related deferred income taxes, may not exceed the present value of future net revenues from proved reserves, plus the lower of cost or market value of unproved properties, less related income tax effects. This "ceiling test" must be performed on a quarterly basis. Based on June 30, 1998, oil and gas prices, the Company's full cost pool book value exceeded its ceiling test value by $1,399,000. Accordingly, the book value of oil and gas properties was written down by this amount as of June 30, 1998. AUSTRALIA The Company's Australia full cost pool includes acquisition, drilling and completion costs, seismic and initial de-watering costs, and costs to construct gas gathering lines. The Company holds a non-operating interest in the Comet Ridge coalbed methane project in Queensland. As of September 30, 1998, the capitalized cost applicable to the Australia full cost pool was $23,149,000. All capitalized costs are subject to depletion and depreciation. As of September 30, 1998, proved reserves were 123 Bcf, an increase of 5.6 Bcf over September 30, 1997. The discounted future net cash flows related to the reserves were $30,680,000 at September 30, 1998, compared to $24,376,000 at September 30, 1997. This increase is attributable to a decrease in estimated future production costs and to the acquisition of an additional 5% interest in the Comet Ridge project for approximately $3,200,000. The Company's capital-bearing interest in the project was 55.75% as of September 30, 1998. F-11 TIPPERARY CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements NOTE 4 - EARNINGS PER SHARE The following table sets forth the computation of basic and diluted earnings (loss) per share (in thousands except per share data):
September 30, ------------------------------- 1998 1997 1996 -------- -------- --------- Numerator: FOR BASIC AND DILUTED NET INCOME (LOSS) PER SHARE - net income (loss) available to common stockholders $ (6,398) $ 472 $ (790) Denominator: FOR BASIC NET INCOME (LOSS) PER SHARE -weighted average shares outstanding 13,118 13,050 11,807 FOR DILUTED NET INCOME (LOSS) PER SHARE - adjusted weighted average shares outstanding and assumed conversion of dilutive option shares 13,118 13,266 11,807 Basic earnings (loss) per share $ (0.49) $ 0.04 $ (0.07) ======== ======== ======== Diluted earnings (loss) per share $ (0.49) $ 0.04 $ (0.07) ======== ======== ========
Potentially dilutive common stock of 145,000 shares and 472,000 shares from the exercise of options and warrants were antidilutive for fiscal years 1998 and 1996 respectively. NOTE 5 - LONG-TERM DEBT The Company's bank credit agreement (the "agreement") provides a maximum loan facility of $40,000,000 subject to borrowing base limitations described below. The agreement contains provisions for both fixed rate and variable rate borrowings. During fiscal 1998, the Company and its bank entered into an amendment to the loan agreement which provided for a two-tranche revolver with interest at either London Interbank Offered Rate ("LIBOR") plus 2.5% or the bank's Base Rate on the first $12,000,000 and either LIBOR plus 3.8% or the bank's Base Rate plus 1% on the remainder. The Company may make the selection between LIBOR or the bank's Base Rate, with the LIBOR-based option available for periods not exceeding 90 days. The outstanding loan balance at September 30, 1998, and September 30, 1997, was $16,500,000 and $13,844,000, respectively. The weighted average interest rate was 8.48% as of September 30, 1998 and 7.19% as of September 30, 1997. Upon expiration of the revolver (the "Conversion Date"), the principal balance will convert to a three-year term loan. During the first quarter of fiscal 1998, the Conversion Date was extended by the bank from October 5, 1998 to October 5, 1999. It may be extended again, although the Company has no such assurance from the bank. Certain of the Company's domestic oil and gas properties have been pledged as security for the bank loan, and the Company recently agreed to pledge other unencumbered properties. The maximum borrowing base is determined solely by the bank and is based upon its assessment of the value of the Company's properties. This bank valuation is based upon the bank's assumptions about reserve quantities, oil and gas prices, operating expenses and other assumptions, all of which may change from time to time and which may differ from the Company's assumptions. At September 30, 1997, the borrowing base was $14,500,000. In February 1998, the bank increased the borrowing base by $2,000,000, to $16,500,000. Based on the recent significant decline in oil and gas prices, the bank reduced the borrowing base to $11,800,000 as of August 31, 1998. Under the terms of the agreement, if the loan balance exceeds the borrowing base, the Company is required to either make a cash payment to the bank equal to or greater than such excess or provide additional collateral to increase the borrowing base by the amount of the deficit. The Company used $4,700,000 of the F-12 TIPPERARY CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements proceeds from the debt and equity financing received from its largest shareholder subsequent to September 30, 1998, to reduce bank debt to the new borrowing base of $11,800,000. See Note 2. The Company is obligated to pay a commitment fee of 3/8% per annum on the difference between the bank's average outstanding loan balance and the borrowing base. The bank agreement provides that the Company may not pay dividends or incur additional debt without the prior approval of the bank. Pursuant to the terms of the bank loan agreement, approximately $3,933,000 is projected to mature in each fiscal year from 2000 through 2003. NOTE 6 - STOCKHOLDERS' EQUITY Stockholders' equity at September 30, 1998, and 1997 consisted of the following (in thousands, except number of shares):
1998 1997 ---- ---- Preferred stock: Cumulative, $1.00 par value. Authorized 10,000,000 shares; none issued $ -- $ -- Non-cumulative, $1.00 par value. Authorized 10,000,000 shares; none issued -- -- Common stock, $.02 par value. Authorized 20,000,000 shares; 13,161,755 issued and 13,133,955 outstanding as of September 30, 1998; 13,078,071 issued and 13,050,271 outstanding in 1997 263 262 Capital in excess of par value 105,564 105,375 Accumulated deficit (75,476) (69,078) Treasury stock, at cost; 27,800 shares (71) (71) --------- --------- Total stockholders' equity $ 30,280 $ 36,488 ========= =========
COMMON STOCK ISSUANCES During fiscal 1998, the Company issued 50,000 shares at $2.00 per share to a former director and 3,100 shares at $2.00 per share to an officer of the Company pursuant to the exercise of warrants. Additionally, the Company issued 30,584 shares of common stock to employees pursuant to the exercise of incentive stock options; 21,000 shares were issued at $2.75 per share, 1,250 shares at $3.52 per share, 1,667 shares at $3.63 per share and 6,667 shares at $4.75 per share. Net proceeds to the Company during fiscal 1998 from the exercise of stock options and warrants were approximately $190,000. STOCK INCENTIVE PLANS In 1987, the Company adopted the 1987 Employee Stock Option Plan (the "1987 Plan") that provided for grant of a maximum of 383,000 options to employees of the Company to purchase shares of the Company's common stock. The 1987 Plan expired December 31, 1996. The 269,400 options currently outstanding under this plan have a term of ten years, 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"). These options remain in full force and effect pursuant to each option's terms. Pursuant to a shareholder vote in January 1997, the 1997 Long-Term Incentive Plan (the "1997 Plan") was adopted to replace the expired 1987 Plan. The 1997 Plan reserves 250,000 shares of common stock for issuance for a period of ten years. Any shares that are the subject of an award which has lapsed or expired unexercised or unissued will automatically become available for reissue under the 1997 Plan. 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 ("SARs"), performance awards related to the Company's operations, or restricted stock upon payment of consideration not less than F-13 the par value of the restricted stock issued. During fiscal 1998, the Company issued additional options to acquire 81,000 shares of its common stock under this plan. The following table represents a summary of stock option transactions under both the 1987 Plan and the 1997 Plan for the three years ended September 30, 1998:
1987 Plan 1997 Plan Price Range per Share --------- --------- --------------------- As of September 30, 1995 259,650 -- $2.75 to $5.13 Granted in fiscal 1996 111,000 -- $4.63 to $4.75 Forfeited in fiscal 1996 (100,000) -- $2.75 Exercised in fiscal 1996 (4,000) -- $2.75 -------- --------- As of September 30, 1996 266,650 -- $2.75 to $5.13 -------- --------- Granted in fiscal 1997 85,000 37,500 $3.63 to $4.56 Forfeited in fiscal 1997 -- -- -- Exercised in fiscal 1997 -- -- -- -------- --------- As of September 30, 1997 351,650 37,500 $2.75 to $5.13 -------- --------- Granted in fiscal 1998 -- 81,000 $4.00 to $4.38 Forfeited in fiscal 1998 (51,666) (17,000) $3.63 to $4.75 Exercised in fiscal 1998 (30,584) -- $2.75 to $4.75 -------- --------- As of September 30, 1998 269,400 101,500 $2.75 to $5.13 ======== ========= Exercisable as of September 30, 1998 202,401 10,835 $2.75 to $5.13 ======== =========
Options under both plans vest ratably over three years, except for options covering 15,000 shares under the 1987 Plan at an exercise price of $5.13, which vested ratably over five years. NONQUALIFIED STOCK OPTIONS AND WARRANTS Nonqualified option and warrant transactions for the three years ended September 30, 1998, are as follows: SHARES PRICE RANGE PER SHARE ------ --------------------- As of September 30, 1995 875,000 $2.00 to $6.00 Granted in fiscal 1996 100,000 $4.31 to $4.63 Expired in fiscal 1996 (133,333) $2.75 to $6.00 Exercised in fiscal 1996 (436,667) $2.00 to $2.75 -------- As of September 30, 1996 405,000 $2.00 to $4.63 -------- Granted in fiscal 1997 105,000 $4.25 Expired in fiscal 1997 -- -- Exercised in fiscal 1997 -- -- -------- As of September 30, 1997 510,000 $2.00 to $4.63 -------- Granted in fiscal 1998 -- -- Expired in fiscal 1998 -- -- Exercised in fiscal 1998 (53,100) $2.00 -------- As of September 30, 1998 456,900 $2.00 to $4.63 ======== Exercisable as of September 30, 1998 353,569 $2.00 to $4.63 ========
F-14 The following table summarizes information about stock options and warrants outstanding at September 30, 1998: Options and Warrants Options and Warrants Outstanding Exercisable ------------------------------------------------------- -------------------------------- Number Weighted Weighted Average Number Weighted Range of Outstanding Average Remaining Exercisable Average Exercise Prices at 9/30/98 Exercise Price Contractual Life at 9/30/98 Exercise Price - --------------- ----------- -------------- ---------------- ----------- -------------- $2.00 to $2.75 355,300 $2.32 8.64 355,300 $2.32 $3.63 to $5.13 472,500 $4.30 8.77 211,505 $4.39 $2.00 to $5.13 827,800 $3.45 8.72 566,805 $3.09
The Company applies Accounting Principles Board Opinion No. 25 , Accounting for Stock Issued to Employees, ("APB 25") and related interpretations to account for its stock option plans. Under APB 25 expense for a stock option is recorded as the difference between the market price of the stock and the exercise price on the date of grant. No compensation expense has been recognized for grants of stock options or warrants, since the plans provide that the exercise price shall be equal to or greater than the market price of the stock on the date of grant. In 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123"). SFAS 123 encourages, but does not require, companies to adopt a method of accounting for stock compensation awards based on the estimated fair value at the date the awards were granted. Companies may decide not to adopt the fair value method but rather to disclose in the notes to the financial statements the pro forma effect on net income and earnings per share had the fair value method been adopted. The fair value of options and warrants granted during fiscal 1998, 1997 and 1996 of $130,000, $431,000 and $471,000, respectively, were estimated using the Black-Scholes option-pricing model with the following weighted-average assumptions: 1998 1997 1996 ---- ---- ---- Expected life (in years) 5.00 6.00 6.00 Expected volatility 66.16% 67.71% 74.40% Risk-free interest rate 5.84% 6.20% 5.90% Expected dividends $ - $ - $ -
Had compensation cost for the Company's plans been determined based on the fair value at the grant dates for awards under these plans consistent with the method of SFAS 123, the Company's net income (loss) and earnings (loss) per share would have been adjusted to the pro forma amounts indicated below: 1998 1997 1996 ---- ---- ---- Net income (loss) As Reported $ (6,398,000) $ 472,000 (790,000) Pro forma $ (6,599,000) 327,000 (855,000) Income (loss) per share As Reported $ (.49) $ .04 $ (.07) Pro forma $ (.50) $ .03 $ (.07)
F-15 NOTE 7 - INCOME TAXES Under Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes," the Company has recorded a $21 million asset for the future benefit of its net operating tax loss carryforwards and other tax benefits. As of September 30, 1998, this asset was offset by a valuation allowance of approximately $19 million based on management's projection of realizability of the gross deferred tax asset. Fluctuations in industry conditions and trends warrant periodic management reviews of the recorded valuation allowance to determine if an increase or decrease in such allowance is appropriate. As of June 30, 1998, NYMEX oil and gas prices had decreased approximately 30% and 20%, respectively, compared to prices as of September 30, 1997. As a result of these price decreases, management revised its assumptions used in projections of taxable income and utilization of net operating loss carryforwards. These revisions, combined with recent net operating tax losses, and the expiration by 2001 of $31 million of approximately $43 million in total tax net operating loss carryfowards, led management to conclude that the impact of lower oil and gas prices warranted an increase of $1,618,000 in the deferred tax asset valuation allowance, with a corresponding charge to deferred tax expense. The net deferred tax asset is comprised of the following at September 30, 1998 and 1997: 1998 1997 ---- ---- Deferred tax assets: Federal and state net operating loss carryforwards $ 15,112 $ 16,749 Statutory depletion carryforwards 2,409 2,437 Property, plant and equipment 3,098 1,463 Tax credit carryforwards 372 588 Capital loss carryforward 68 204 Other 3 2 - - -------- -------- Gross deferred tax assets 21,062 21,443 -------- -------- Valuation allowance (19,489) (18,252) -------- -------- Net deferred tax asset $ 1,573 $ 3,191 ======== ========
The principal differences between recognition of taxable income (loss) for federal income tax and financial reporting purposes relate to intangible drilling costs, dry hole and abandonment costs, accelerated depreciation and asset write-downs. Income tax expense (benefit) is different than the expected amount computed using the applicable federal statutory income tax rate of 35%. The reasons for and effects of such differences (in thousands) are as follows: 1998 1997 1996 ---- ---- ---- Expected amount $(1,673) $ 165 $ (279) Increase (decrease) from: Increase (decrease) in valuation allowance 1,237 (724) (446) Adjustments to and expiration of carryforwards 2,059 1,127 817 Permanent differences between financial statement income and taxable income (5) (568) (84) State taxes, net of federal benefit, and other -- 1 (14) ------- ------- ------- Total income tax expense (benefit) $ 1,618 $ 1 $ (6) ======= ======= =======
F-16 The Company has approximate net operating loss, capital loss and investment tax credit carryfowards (in thousands) available at September 30, 1998, as follows: Expiration Year Net Operating Loss Capital Loss Investment Tax Credit --------------- ------------------ ------------ --------------------- 1999 $12,252 $ - $ 112 2000 13,701 - 31 2001 4,817 15 14 2002 - 180 - 2003 991 - - 2004 3,360 - - 2009 1,391 - - 2011 1,142 - - 2012 1,962 - - 2018 3,027 - - ------- ----- ------ Total $42,643 $ 195 $ 157 ======= ===== ======
The Company also has statutory depletion carryforwards of approximately $6,884,000 and minimum tax credit carryforwards of approximately $215,000 which do not expire. The Company'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 after 1986. As of September 30, 1998, no such ownership change had occurred. NOTE 8 - COMMITMENTS AND CONTINGENCIES The Company is plaintiff in a lawsuit filed on August 6, 1998, styled TIPPERARY CORPORATION AND TIPPERARY OIL & GAS (AUSTRALIA) PTY LTD. V. TRI-STAR PETROLEUM COMPANY, Cause No. CV42,265, in the District Court of Midland County, Texas. The complaint, which concerns the Comet Ridge coalbed methane project in Queensland, Australia, alleges that Tri-Star Petroleum Company ("Tri-Star"), operator of the project, has failed to perform its duties under the operating agreement, and seeks the removal of Tri-Star as operator, an accounting of expenses charged to the joint interest account and unspecified amounts for damages for breach of contract. Among the allegations in the complaint are that Tri-Star has refused to allow the Company to inspect the books and records of the project, has attempted to block the Company's right to take its proportionate share of gas production in kind, may have improperly billed expenses to the joint interest owners and has an impermissible conflict of interest precluding it from acting as a reasonable and prudent operator. On March 14, 1997, the Company filed a complaint along with several other plaintiffs in BTA OIL PRODUCERS, ET AL. V. MDU RESOURCES GROUP, INC., ET AL. in Stark County Court in the Southwest Judicial District of North Dakota. The plaintiffs are suing the defendants for breach of gas sales contracts, unjust enrichment, implied trust and related business torts. The case concerns the sale by plaintiffs and certain predecessors of natural gas processed at the McKenzie Gas Processing Plant in North Dakota to Koch Hydrocarbons Company. It also concerns the contracts for resale of that gas to MDU Resources Group, Inc. and Williston Basin Interstate Pipeline Company. The defendants have answered the complaint denying the claims, and discovery is in process. YEAR 2000 The year 2000 compliance issue, which is common to most companies, concerns the inability of computer information systems to properly recognize and process date sensitive information as the year 2000 approaches. This could result in errors in information or significant system failures causing disruptions of normal business operations. The Company expects to resolve all issues relating to reprogramming, replacing and testing the affected computer systems prior to December 31, 1999, so that they are year 2000 compliant. To this end, the Company has scheduled an upgrade of its core management information systems during February 1999 so that they will function properly with respect to the year 2000 and beyond. In addition, the Company is currently conducting an inventory, review and F-17 assessment of its desktop computers, networks, servers, and software applications to determine if they are year 2000 compliant. Management is also reviewing non-information technology systems and believes that they are in compliance. The Company will initiate discussions with significant suppliers, purchasers and financial institutions to ensure those parties have addressed year 2000 issues and to assess the extent to which the Company's operations may be impacted should those organizations fail to properly update their computer systems. The Company cannot guarantee that there will not be material adverse effects if these third parties fail to convert their systems in a timely manner and currently believes this to be its most significant risk relating to the year 2000 issue. In order to mitigate the risk of potential failure of third parties to achieve year 2000 compliance, contingency plans are being developed and the Company will survey its significant suppliers and customers to ascertain the status of their conversions and contingency plans. The cost of the year 2000 project is not expected to be material. Funding will be provided by operating cash flows and costs will be expensed as incurred. Time and costs estimates are based on currently available information. Actual results could differ materially from these estimates. OTHER COMMITMENTS AND CONTINGENCIES The Company entered into an amendment to its office lease agreement in Denver, Colorado effective September 1, 1998. The amended lease covers approximately 11,000 square feet and extends the lease for a term of three years. During the term of the lease, the base rent is payable in the amounts: $132,000 in fiscal 1999; $166,000 in fiscal 2000; and $152,000 in fiscal 2001, plus expense recovery amounts. During each of the fiscal years ended September 30, 1998, 1997 and 1996, the Company paid approximately $116,000 in office rent. The Company is subject to various 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, adjustments could be required as new interpretations and regulations are issued. F-18 TIPPERARY CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements NOTE 9 - SUPPLEMENTARY INFORMATION ON OIL AND GAS OPERATIONS (UNAUDITED) Certain historical costs and operating information relating to the Company's oil and gas producing activities for fiscal 1998, 1997 and 1996 (in thousands) are as follows:
CAPITALIZED COSTS: United States Australia Total ------------- --------- --------- September 30, 1998: Proved oil and gas properties $ 103,701 $ 23,345 $ 127,046 Unproved oil and gas properties 9,601 -- 9,601 --------- --------- --------- 113,302 23,345 136,647 Less accumulated depletion (90,736) (196) (90,932) --------- --------- --------- Net capitalized costs $ 22,566 $ 23,149 $ 45,715 ========= ========= ========= September 30, 1997: Proved oil and gas properties $ 103,600 $ 18,460 $ 122,060 Unproved oil and gas properties 9,518 -- 9,518 --------- --------- --------- 113,118 18,460 131,578 Less accumulated depletion (87,187) -- (87,187) --------- --------- --------- Net capitalized costs $ 25,931 $ 18,460 $ 44,391 ========= ========= ========= September 30, 1996: Proved oil and gas properties $ 100,882 $ -- $ 100,882 Unproved oil and gas properties 8,716 12,724 21,440 --------- --------- --------- 109,598 12,724 122,322 Less accumulated depletion (83,881) -- (83,881) --------- --------- --------- Net capitalized costs $ 25,717 $ 12,724 $ 38,441 ========= ========= =========
Total capitalized costs for fiscal 1996 do not include $38,000 of costs incurred for a prospect-generating joint venture in China. These costs were written off in fiscal 1997.
COSTS INCURRED: United States Australia Total ------------- --------- --------- September 30, 1998: Property acquisition costs: Proved oil and gas properties $ -- $ 3,201 $ 3,201 Unproved oil and gas properties 733 -- 733 --------- --------- --------- 733 3,201 3,934 --------- --------- --------- Exploration costs 1,953 -- 1,953 Development costs 352 1,684 2,036 --------- --------- --------- Total costs incurred $ 3,038 $ 4,885 $ 7,923 ========= ========= ========= September 30, 1997: Property acquisition costs: Proved oil and gas properties $ -- $ -- $ -- Unproved oil and gas properties 802 2,309 3,111 --------- --------- --------- 802 2,309 3,111 --------- --------- --------- Exploration costs 849 -- 849 Development costs 1,908 3,427 5,335 --------- --------- --------- Total costs incurred $ 3,559 $ 5,736 $ 9,295 ========= ========= =========
F-19
COSTS INCURRED (Continued): United States Australia Total ------------- --------- --------- September 30, 1996: Property acquisition costs: Proved oil and gas properties $ 13 $ -- $ 13 Unproved oil and gas properties 774 6,092 6,866 --------- --------- --------- 787 6,092 6,879 --------- --------- --------- Exploration costs 627 -- 627 Development costs 1,763 1,507 3,270 --------- --------- -------- Total costs incurred $ 3,177 $ 7,599 10,776 ========= ========= ========
Depletion rates per equivalent barrel of domestic production for the years ended September 30, 1998, 1997 and 1996 were $5.50, $4.51 and $4.87, respectively. Costs of $3,608,000, $3,417,000 and $2,589,000 related to domestic unproved oil and gas properties which have not yet been evaluated were excluded from depletable costs in fiscal 1998, fiscal 1997 and fiscal 1996, respectively. The rate of depletion per equivalent barrel of production in Australia was $1.20 for the year ended September 30, 1998. RESULTS OF OPERATIONS: The results of operations for petroleum producing activities, excluding corporate overhead and interest costs, for each year in the three-year period ended September 30, 1998, (in thousands) are as follows:
United States Australia Total ------------- --------- --------- September 30, 1998: Revenue from sale of oil and gas $ 8,494 $ 452 $ 8,946 Production costs (4,487) (476) (4,963) Depreciation, depletion and amortization including impairment (4,948) (196) (5,144) Income tax expense -- -- -- --------- --------- -------- Operating income from petroleum producing activities $ (941) $ (220) $ (1,161) ========= ========= ======== United States Australia Total ------------- --------- --------- September 30, 1997: Revenue from sale of oil and gas $ 12,791 $ -- $ 12,791 Production costs (5,499) -- (5,499) Depreciation, depletion and amortization (3,345) -- (3,345) Income tax expense (80) -- (80) --------- --------- -------- Operating income from petroleum producing activities $ 3,867 $ -- $ 3,867 ========= ========= ======== United States Australia Total ------------- --------- --------- September 30, 1996: Revenue from sale of oil and gas $ 10,965 $ -- $ 10,965 Production costs (5,463) -- (5,463) Depreciation, depletion and amortization (3,543) -- (3,543) Income tax expense (39) -- (39) --------- --------- -------- Operating income from petroleum producing activities $ 1,920 $ -- $ 1,920 ========= ========= ========
F-20 TIPPERARY CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements Revenues of $136,000, $160,000 and $171,000 were not included above for 1998, 1997 and 1996, respectively, which represent revenues received primarily for saltwater disposal. Production costs of $144,000 were included above for each of 1998, 1997 and 1996, which represent costs paid or payable to other affiliates in the consolidated group. Costs associated with the saltwater disposal revenue and other costs of $134,000, $150,000 and $228,000 were not included above for 1998, 1997 and 1996, respectively. Income tax expense is computed using the Company's overall effective tax rate for each respective year. ESTIMATES OF PROVED OIL AND GAS RESERVES: 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 the Company, and independent petroleum engineers: Netherland, Sewell & Associates, Inc., Forrest A. Garb & Associates, Inc.; and S. A. Holditch & Associates, Inc.
United States Australia Total ------------------ ----------------- --------------------- Oil Gas Oil Gas Oil Gas MBbls MMcf MBbls MMcf MBbls MMcf ------- ------ ------- ------ ------- -------- September 30, 1998: Total proved reserves: Beginning of year 2,916 11,324 - 116,949 2,916 128,273 Revisions of previous estimates (439) (279) - (4,141) (439) (4,420) Extensions, discoveries and other additions 410 189 - -- 410 189 Purchases of reserves in place -- -- - 10,679 -- 10,679 Sale of reserves in place (73) (891) - -- (73) (891) Production (426) (1,320) - (978) (426) (2,298) ----- ------ ----- ------- ----- ------- End of Year 2,388 9,023 - 122,509 2,388 131,532 ===== ====== ===== ======== ===== ======= Proved developed reserves: Beginning of year 2,631 9,473 - 48,396 2,631 57,869 ===== ====== ===== ======== ===== ======= End of Year 2,114 7,255 - 28,100 2,114 35,355 ===== ====== ===== ======== ===== ======= September 30, 1997: Total proved reserves: Beginning of year 4,042 13,052 - -- 4,042 13,052 Revisions of previous estimates (708) (199) - -- (708) (199) Extensions, discoveries and other additions 63 36 - 116,949 63 116,985 Purchases of reserves in place -- -- - -- -- -- Sale of reserves in place -- -- - -- -- -- Production (481) (1,565) - -- (481) (1,565) ----- ------ ----- ------- ----- ------- End of Year 2,916 11,324 - 116,949 2,916 128,273 ===== ====== ===== ======== ===== ======= Proved developed reserves: Beginning of year 3,657 11,116 - -- 3,657 11,116 ===== ====== ===== ======== ===== ======= End of Year 2,631 9,473 - 48,396 2,631 57,869 ===== ====== ===== ======== ===== =======
F-21 TIPPERARY CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements ESTIMATES OF PROVED OIL AND GAS RESERVES (Continued):
United States Australia Total ------------------ ----------------- --------------------- Oil Gas Oil Gas Oil Gas MBbls MMcf MBbls MMcf MBbls MMcf ------- ------ ------- ------ ------- -------- September 30, 1996: Total proved reserves: Beginning of year 3,419 13,061 - - 3,419 13,061 Revisions of previous estimates 835 1,556 - - 835 1,556 Extensions, discoveries and other additions 288 193 - - 288 193 Purchases of reserves in place 12 18 - - 12 18 Sale of reserves in place (42) (226) - - (42) (226) Production (470) (1,550) - - (470) (1,550) ----- ------ ----- ------- ----- ------- End of Year 4,042 13,052 - - 4,042 13,052 ===== ====== ===== ======== ===== ======= Proved developed reserves: Beginning of year 2,952 10,798 - - 2,952 10,798 ===== ====== ===== ======== ===== ======= End of Year 3,657 11,116 - - 3,657 11,116 ===== ====== ===== ======== ===== =======
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS: Information with respect to the Company's estimated discounted future net cash flows from its oil and gas properties for fiscal 1998, 1997 and 1996 (in thousands) follows:
United States Australia Total ------------- --------- --------- September 30, 1998: Future revenues $ 53,779 $ 150,196 $203,975 Future production costs (24,095) (31,649) (55,744) Future development costs (1,439) (9,887) (11,326) Future income tax expense (1,045) (38,108) (39,153) --------- --------- -------- Future net cash flow 27,200 70,552 97,752 10% annual discount (11,024) (39,872) (50,896) --------- --------- -------- Discounted future net cash flows $ 16,176 $ 30,680 $ 46,856 ========= ========= ======== September 30, 1997: Future revenues $ 92,359 $ 159,953 $252,312 Future production costs (37,309) (47,670) (84,979) Future development costs (1,460) (8,463) (9,923) Future income tax expense (2,739) (33,067) (35,806) --------- --------- -------- Future net cash flow 50,851 70,753 121,604 10% annual discount (20,600) (46,377) (66,977) --------- --------- -------- Discounted future net cash flows $ 30,251 $ 24,376 $ 54,627 ========= ========= ======== September 30, 1996: Future revenues $ 115,708 - $115,708 Future production costs (48,297) - (48,297) Future development costs (2,215) - (2,215) Future income tax expense (2,607) - (2,607) --------- --------- -------- Future net cash flow 62,589 - 62,589 10% annual discount (24,652) - (24,652) --------- --------- -------- Discounted future net cash flows $ 37,937 $ - $ 37,937 ========= ========= ========
F-22 TIPPERARY CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements Principal changes in the Company's estimated discounted future net cash flows for each of the three years in the period ended September 30, 1998 (in thousands) are as follows:
United States Australia Total ------------- --------- --------- September 30, 1998: Beginning of year $ 30,251 $ 24,376 $ 54,627 Oil and gas sales, net of production costs (4,151) (1,193) (5,344) Net change in prices and production costs (10,946) 7,241 (3,705) Extensions and discoveries, less related costs 2,535 -- 2,535 Purchases of reserves in place, net -- 3,204 3,204 Sale of reserves in place (1,726) -- (1,726) Change in estimated development costs 17 1,344 1,361 Revision of previous quantity estimates (3,047) (5,176) (8,223) Accretion of discount 3,025 2,438 5,463 Net change in income taxes 1,062 (2,134) (1,072) Changes in production rates and other (844) 580 (264) --------- --------- -------- End of year $ 16,176 $ 30,680 $ 46,856 ========= ========= ========
At September 30, 1998, average oil and gas prices used in the determination of future cash flows for domestic reserves were $13.91 per barrel and $2.28 per Mcf, respectively. The average gas price used in the determination of future cash flows for Australia reserves was U.S. $1.23 per Mcf.
United States Australia Total ------------- --------- --------- September 30, 1997: Beginning of year $ 37,937 $ -- $ 37,937 Oil and gas sales, net of production costs (7,436) -- (7,436) Net change in prices and production costs 1,554 -- 1,554 Extensions and discoveries, less related costs 441 24,376 24,817 Change in estimated development costs 720 -- 720 Revision of previous quantity estimates (4,523) -- (4,523) Accretion of discount 3,794 -- 3,794 Net change in income taxes (276) -- (276) Changes in production rates and other (1,960) -- (1,960) --------- --------- -------- End of year $ 30,251 $ 24,376 $ 54,627 ========= ========= ========
At September 30, 1997, average oil and gas prices used in the determination of future cash flows for domestic reserves were $19.01 per barrel and $3.26 per Mcf, respectively. The average gas price used in the determination of future cash flows for foreign reserves was $1.37 per Mcf; the Company had not entered into a gas contract, but believes this price was representative of general market conditions as of September 30, 1997.
United States Australia Total ------------- --------- --------- September 30, 1996: Beginning of year $ 24,200 $ -- $ 24,200 Oil and gas sales, net of production costs (5,646) -- (5,646) Net change in prices and production costs 10,185 -- 10,185 Extensions and discoveries, less related costs 2,006 -- 2,006 Purchases of reserves in place, net 89 -- 89 Sales of reserves in place, net (247) -- (247) Change in estimated development costs 596 -- 596 Revision of previous quantity estimates 4,735 -- 4,735 Accretion of discount 2,420 -- 2,420 Net change in income taxes (1,114) -- (1,114) Changes in production rates and other 713 -- 713 --------- --------- -------- End of year $ 37,937 $ -- $ 37,937 ========= ========= ========
At September 30, 1996 average oil and gas prices used in the determination of future cash flows were $22.48 per barrel and $1.90 per Mcf, respectively. F-23 TIPPERARY CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements NOTE 10 - QUARTERLY RESULTS OF OPERATIONS (UNAUDITED) The following is a summary of the unaudited quarterly results of operations for the fiscal years ended September 30, 1998 and 1997 (in thousands, except per share data):
Quarter Ended -------------------------------------------------------- December 31, March 31, June 30, September 30, 1997 1998 1998 1998 Total ------------ --------- -------- -------------- -------- FISCAL 1998 Revenues $ 2,564 $ 2,244 $ 2,224 $ 2,050 $ 9,082 ======= ======= ======= ======= ======= Gross profit $ 1,301 $ 1,056 $ 993 $ 779 $ 4,129 ======= ======= ======= ======= ======= Net income (loss) $ (294) $ (705) $(3,750)(1) $(1,649) $(6,398) ======= ======= ======= ======= ======= Net income (loss) per common share - basic and diluted $ (.02) $ (.05) $ (.29) $ (.13) $ (.49) ======= ======= ======= ======= =======
Quarter Ended -------------------------------------------------------- December 31, March 31, June 30, September 30, 1996 1997 1997 1997 Total ------------ --------- -------- -------------- -------- FISCAL 1997 Revenues $ 4,112 $ 3,064 $ 3,020 $ 2,755 $12,951 ======= ======= ======= ======= ======= Gross profit $ 2,642 $ 1,618 $ 1,742 $ 1,444 $ 7,446 ======= ======= ======= ======= ======= Net income (loss) $ 978 $ 185 $ (587)(2) $ (104) $ 472 ======= ======= ======= ======= ======= Net income (loss) per common share - basic and diluted $ .07 $ .01 $ (.04) $ .00 $ .04 ======= ======= ======= ======= =======
(1) Includes $1,399 write-down of oil and gas properties and $1,618 write-down of deferred tax asset. (2) Includes $467 write-down of investment in NGL fractionator and $258 loss on disposition of UXP common stock. F-24 EX-4.57 2 EXHIBIT 4.57 PROMISSORY NOTE $1,000,000 Denver, Colorado August 31, 1998 Tipperary Corporation, a Texas corporation ("Maker"), hereby promises to pay to the order of Slough Estates USA Inc., a Delaware corporation ("Lender"), at its office located at 33 West Monroe Street, Chicago, Illinois 60603, or at any other place the holder hereafter designates, the principal sum of $1,000,000, or the lesser sum of such amounts as Lender may advance to Maker from time to time hereunder, together with interest thereon in lawful money of the United States as herein provided. 1. INTEREST. The unpaid principal balance of this Note shall bear interest commencing on the date proceeds of the loan are received by Maker after written request for loan proceeds are provided to Lender, such interest to be at the rate of 8.5% per annum, payable in calendar quarterly installments. Each such quarterly interest payment shall be due and payable within five days of the end of each calendar quarter. Interest shall be calculated based on the actual number of days the principal balance remains outstanding in a year of 365 days. 2. MATURITY. The unpaid principal balance of this Note, together with accrued and unpaid interest, shall be due and payable in full one year from the date of the initial advance of funds by Lender hereunder. 3. SECURITY. This Note is secured by a security agreement of even date herewith, in favor of Lender, with respect to 10% of the interest in the joint operating agreement in respect of the Comet Ridge project located in Queensland, Australia, which is the same collateral granted incident to that certain Promissory Note, dated December 20, 1996, in the principal sum of $2,300,000, executed by Maker and Lender. 4. PREPAYMENT. The unpaid principal balance of the Note, together with accrued and unpaid interest, may be paid in whole or in part, at any time in the sole discretion of Maker without penalty. Any prepayment in part by Maker shall be first allocated to any accrued and unpaid interest, with any remaining amount being allocated to the unpaid principal. 5. DEFAULT. If any of the following events occurs, all indebtedness owing by Maker hereunder shall become forthwith due and payable to Lender, upon delivery by Lender to Maker of a written notice of default and demand for payment, and the expiration of 30 days from the delivery of such notice, during which period Maker shall have the ability to cure such default. a. Any default by Maker in the payment, when due, of any part of the principal of or interest on this Note and the payment of any other sums payable by Maker pursuant to the terms of this Note. b. Maker's insolvency or bankruptcy, the execution by Maker of an assignment for the benefit of creditors of substantially all of Maker's assets, or Maker's consent to the appointment of a trustee or a receiver or other officer of a court or other tribunal. c. The appointment of a trustee or receiver or other officer of a court for Maker, or for a substantial part of its properties, without its consent, where no discharge is effected within 30 days. d. The institution of bankruptcy, reorganization, insolvency, or liquidation proceedings by or against Maker, and if against Maker, where such proceeding is consented to by it or remains undismissed for 30 days. e. Any breach or failure of Maker to perform any term or condition of this Note. 6. USE OF PROCEEDS. The proceeds from this Note shall be used for the general corporate purposes of Maker. 7. ASSIGNMENT. This Note may not be assigned by Lender or Maker without the express written consent of the other party. 8. GOVERNING LAW. This Note is made and is being executed in the State of Colorado, and the provisions hereof will be construed in accordance with the laws of the State of Colorado. Furthermore, Lender and Maker (and their lawful assignees, successors and endorsers) further agree that in the event of default this Note may be enforced in any court of competent jurisdiction in the State of Colorado, and they do hereby submit to such jurisdiction in the State of Colorado. 9. SEVERABILITY. Invalidation of any of the provisions of this Note shall not affect the remainder of this Note. 10. AMENDMENT. This Note may not be amended or modified except by an instrument in writing signed by both parties. 11. SUBORDINATION. This Note is subject to the terms and provisions of a Subordination Agreement, dated December 20, 1996, as amended, between Lender and Colorado National Bank, which terms and provisions are incorporated herein by reference. TIPPERARY CORPORATION By: s/b David L. Bradshaw ---------------------------------- David L. Bradshaw, President and Chief Executive Officer SLOUGH ESTATES USA INC. By: s/b R. W. Rohner --------------------------------------- Randall W. Rohner, Vice President and Chief Financial Officer 2 SECURITY AGREEMENT THIS AGREEMENT is made this 31st day of August, 1998, by and between Tipperary Corporation, a Texas corporation ("Debtor"), whose principal place of business is 633 Seventeenth Street, Suite 1550, Denver, Colorado 80202, and Slough Estates USA Inc., a Delaware corporation ("Secured Party"), whose office is located at 33 Monroe Street, Chicago, Illinois 60603. In consideration of the mutual covenants and promises set forth herein, Debtor and Secured Party agree: 1. Debtor hereby grants to Secured Party a security interest in the Collateral, described in Section 2, to secure performance and payment of Debtor's Promissory Note, of even date herewith, in the amount of $1,000,000, given to Secured Party and payable as to principal and interest as therein provided. 2. The Collateral (which is the same collateral granted in that certain Security Agreement, dated December 20, 1996, between Debtor and Secured Party, incident to a Promissory Note of the same date in the principal amount of $2,300,000) subject to this Agreement consists of 10% of the rights, interests and obligations in that certain amended Joint Operating Agreement, dated as of May 15, 1992, to which Tri-Star Petroleum Company, a Texas corporation, is a party and Operator, and of which Debtor is owner, with respect to certain Australian coalbed methane properties and prospective coalbed methane properties as therein provided. 3. Debtor will not, without the written consent of Secured Party, sell, contract to sell, lease, encumber or otherwise dispose of the Collateral or any interest therein until this Agreement and all obligations hereby have been fully satisfied. 4. Upon any default hereunder, Secured Party may proceed to exercise any and all rights and remedies provided by Colorado law. 5. This Agreement shall be construed according the laws of the State of Colorado. IN WITNESS WHEREOF, the parties hereto have executed and delivered this Agreement on the date first above written. TIPPERARY CORPORATION SLOUGH ESTATES USA INC. By: s/b David L. Bradshaw By: s/b R. W. Rohner -------------------------------- --------------------------------- David L. Bradshaw, President and Randall W. Rohner, Vice President Chief Executive Officer and Chief Financial Officer EX-11.1 3 EXHIBIT 11.1 TIPPERARY CORPORATION AND SUBSIDIARIES Calculation of Weighted Average Number of Shares Outstanding Years Ended September 30, 1996, 1997 and 1998 (in thousands)
Number Weighting Weighted Description of Transaction of Shares Factor Average - ------------------------------ --------- --------- -------- Year ended September 30, 1996: Basic & Diluted Shares Beginning of period 11,210 365/365 11,210 Common stock issuances 1,400 137/365 525 Shares issued upon exercise of options and warrants 440 60/365 72 Common stock equivalents (1) 472 -- ------ ------ End of period 13,522 11,807 ------ ------ ------ ------ Year ended September 30, 1997: Basic Shares Beginning of period 13,050 365/365 13,050 Common stock issuances -- -- Shares issued upon exercise of options and warrants -- -- Common stock equivalents -- -- ------ ------ End of period 13,050 13,050 ------ ------ ------ ------ Year ended September 30, 1997: Diluted Shares Beginning of period 13,050 365/365 13,050 Common stock issuances -- -- Shares issued upon exercise of options and warrants -- -- Common stock equivalents 216 365/365 216 ------ ------ End of period 13,266 13,266 ------ ------ ------ ------ Year ended September 30, 1998: Basic & Diluted Shares Beginning of period 13,050 365/365 13,050 Common stock issuances Shares issued upon exercise of options and warrants 84 295/365 68 Common stock equivalents (1) 145 -- ------ ------ End of period 13,279 13,118 ------ ------ ------ ------
(1) Antidilutive and therefore excluded from computation of weighted average shares outstanding EX-21.1 4 EXHIBIT 21.1 EXHIBIT 21.1 TIPPERARY CORPORATION AND SUBSIDIARIES Corporation State or Other Jurisdiction of Incorporation - ---------------------------------------- ---------------------------------- Tipperary Corporation Texas Tipperary Oil & Gas Corporation Texas Tipperary Oil & Gas (Australia) Pty Ltd. Queensland, Australia Burro Pipeline Corporation New Mexico EX-23.1 5 EXHIBIT 23.1 CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the incorporation by reference of our report dated December 22, 1998, appearing on page F-2 of Tipperary Corporation's Annual Report on Form 10-K for the year ended September 30, 1998, in the following: 1. Registration Statement on Form S-8 (No. 333-40589) with respect to Tipperary Corporation Common Stock Issued Pursuant to the 1995 Compensatory Warrant. 2. Prospectus constituting part of the Registration Statement on Form S-3 (No. 333-5653) with respect to Tipperary Corporation Common Stock Issued to the Heartland Small Cap Contrarian Fund and The Acorn Fund. 3. Registration Statement on Form S-8 (No. 33-61017) with respect to the Tipperary Corporation Common Stock Issued Pursuant to the 1987 Employee Stock Option Plan. /s/ PricewaterhouseCoopers LLP PricewaterhouseCoopers LLP Denver, Colorado December 22, 1998 EX-27 6 EXHIBIT 27
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE CONSOLIDATED BALANCE SHEET AND CONSOLIDATED STATEMENT OF OPERATIONS FOUND ON PAGES F-3, F-4 AND F-5 OF THE COMPANY'S FORM 10-K FOR THE YEAR ENDED SEPTEMBER 30, 1998, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 YEAR SEP-30-1998 OCT-01-1997 SEP-30-1998 633 0 1,408 0 218 2,325 139,218 92,626 50,760 1,280 19,200 0 0 263 30,017 50,760 9,082 9,082 4,953 12,518 (10) 0 1,354 (4,780) 1,618 (6,398) 0 0 0 (6,398) (.49) (.49)
EX-99.1 7 EXHIBIT 99.1 RISK FACTORS ------------ The following factors should be considered carefully before purchasing the Shares offered by this Prospectus. GENERAL INDUSTRY CONSIDERATIONS - ------------------------------- VOLATILITY OF OIL AND GAS PRICES AND MARKETS. The Company's revenues and earnings are determined, to a large degree, by prevailing prices for oil and gas. Historically, oil and gas prices and markets have been volatile and are likely to continue to be volatile. Prices for oil and gas are subject to wide fluctuations in response to relatively minor changes in supply of and demand for oil and gas, market uncertainty and numerous additional factors that are beyond the control of the Company. DRILLING AND OPERATING RISKS. The Company's oil and gas operations are subject to all of the risks and hazards typically associated with drilling for, and production and transportation of, oil and gas. These risks include the necessity of spending large amounts of money for identification and acquisition of properties and for drilling and completion of wells. In the drilling of exploratory or development wells, failures and losses may occur before any deposits of oil or gas are found. The presence of unanticipated pressure or irregularities in formations, blow-outs or accidents may cause such activity to be unsuccessful, resulting in a loss of the Company's investment in such activity. If oil or gas is encountered, there can be no assurance that it can be produced in economic quantities sufficient to justify the cost of continuing such operations or that it can be marketed satisfactorily. OPERATING HAZARDS AND UNINSURED RISKS. The oil and gas business involves a variety of operating risks, including fire, explosion, pipe failure, casing collapse, abnormally pressured formations, and environmental hazards such as oil spills, gas leaks, and discharges of toxic gases. The occurrence of any of these events with respect to any property operated or owned (in whole or in part) by the Company could have a material adverse impact on the Company. The Company and the operators of its properties maintain insurance in accordance with customary industry practices and in amounts that management believes to be reasonable. However, insurance coverage is not always economically feasible and is not obtained to cover all types of operational risks. The occurrence of a significant event that is not fully insured could have a material adverse effect on the Company's financial condition. COMPETITION. The oil and gas industry is highly competitive. The Company competes in the areas of property acquisitions and the development and production of oil and gas with major oil companies and other independent oil and gas concerns, as well as with individual producers and operators. Many of these competitors have substantially greater financial and other resources than the Company. ENVIRONMENTAL AND OTHER GOVERNMENTAL REGULATION. Oil and gas operations in the United States are subject to various Federal, state and local governmental regulations. The production, - 1 - handling, transportation and disposal of oil and gas and their by-products are subject to regulation under Federal, state and local environmental laws. To date, the Company has not been required to expend significant resources in order to satisfy applicable environmental laws and regulations applicable to domestic operations. However, compliance costs under existing legal requirements and under any new requirements that might be enacted could become material. Additional matters subject to governmental regulation in the United States include discharge permits for drilling operations, performance bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, Federal and state regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and gas wells below actual production capacity in order to conserve supplies of oil and gas. The regulation of the petroleum industry in Australia is similar to that of the United States and is imposed at both the commonwealth and state level. Regulations in Australia impose environmental, cultural heritage and native title restrictions on accessing resources. In addition, legislation in the State of Queensland regulates construction of pipelines and the royalties payable. The cost of complying with environmental and other regulations applicable to the Company's Australian operations cannot be estimated at this time. SPECIFIC COMPANY CONSIDERATIONS - ------------------------------- UNCERTAINTY OF ESTIMATES OF RESERVES AND FUTURE NET REVENUES. Certain published materials of the Company contain estimates of the Company's oil and gas reserves and the discounted future net revenues from those reserves, as prepared by independent petroleum engineers and/or the Company. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, including many factors beyond the control of the Company. Those estimates are based on several assumptions that the SEC requires oil and gas companies to use, for example, constant oil and gas prices. Such estimates are inherently imprecise indications of future net revenues. Actual future production, revenues, taxes, operating expenses, development expenditures and quantities of recoverable oil and gas reserves might vary substantially from those assumed in the estimates. Any significant variance in these assumptions could materially affect the estimated quantity and value of reserves. In addition, the Company's reserves might be subject to revision based upon future production, results of future exploitation and development, prevailing oil and gas prices and other factors. OPERATING CAPITAL AND CASH FLOW. The Company anticipates that in order to pursue both its domestic and international projects, cash on hand, existing cash flows and bank financing will have to be supplemented with project financing and/or additional corporate debt or equity. The Company expects to continue to incur capital expenditures in excess of operating cash flows, which will further decrease its cash and temporary investments. The Company has minimal remaining unused borrowing capacity and is therefore attempting to establish additional oil and gas reserves through its exploitation and exploration projects which, if successful, could increase its borrowing base with the bank. Also, to offset the reductions in cash, the Company may seek to sell various properties. The Company is also exploring various capital raising options in order to proceed with its business - 2 - plan. However, there can be no assurance that sufficient capital will be obtained from financing and sales transactions or, if obtained, that the transactions will be on terms acceptable to the Company or on a basis that meets the Company's objectives. The Company has entered into hedge positions to partially mitigate the effects of lower oil and gas prices and corresponding adverse effects on cash flow. Notwithstanding the Company's hedging activities, significant decreases in oil and gas prices could cause a significant reduction in cash flows available for the funding of capital projects, particularly in light of the Company's limited cash and cash equivalents, and could negatively impact the Company's efforts to secure new financing. AVAILABILITY OF NET OPERATING LOSS CARRYFORWARDS. As of September 30, 1997, the Company had net operating loss carryforwards for Federal income tax purposes of approximately $46.9 million, which expire at various dates through fiscal 2012 (subject to certain limitations). The utilization of these carryforwards effectively lowers the Company's current Federal income tax rate from approximately 35% to approximately 2%, and therefore provides a significant benefit to the Company to the extent it generates taxable income. Under complex Federal income tax rules, the Company's net operating loss carryforwards would be subjected to an annual limitation should there be a change of over 50% in the stock ownership of the Company during any three-year period. For example, the annual use of the net operating loss carryforwards could be limited if the Company issued substantial amounts of Common Stock, or its largest stockholders sold substantial amounts of their Common Stock. Also, if the Company were to be acquired by a tender offer, merger, or similar transaction, the acquiror could be limited in its ability to utilize the loss carryforwards, and the purchase price for the Company could be adversely affected. DEPENDENCE UPON KEY MANAGEMENT. The operations of the Company are substantially dependent upon David L. Bradshaw, its President, Chief Executive Officer and a Director, and Jeff T. Obourn, its Senior Vice President -Operations. The Company has no key man life insurance on either Mr. Bradshaw or Mr. Obourn. The loss of services of any such person to the Company could have a material adverse impact on the Company. SHARES ELIGIBLE FOR FUTURE SALE. Sales of substantial amounts of Common Stock in the public market by officers, directors and principal stockholders of the Company through the exercise of registration rights or subject to compliance with certain volume limitations as prescribed by Rule 144 under the Act could adversely affect the market price for the Common Stock. CONTINUING CONTROL BY EXISTING PRINCIPAL STOCKHOLDERS AND MANAGEMENT. Existing principal stockholders and management own approximately 37% of the outstanding shares of Common Stock. Such persons are, as a practical matter, able to elect all members of the Company's Board of Directors and control the Company. FINANCIAL REPORTING IMPACT OF FULL COST METHOD OF ACCOUNTING. The Company follows the full cost method of accounting for its oil and gas properties. Under such method, the net book value - 3 - of properties on a country by country basis, less related deferred income taxes, may not exceed a calculated "ceiling." The ceiling is the estimated future after tax net revenues from proved oil and gas properties, discounted at 10% per year. In calculating discounted future net revenues, oil and gas prices in effect at the time of the calculation are held constant, except for changes which are fixed and determinable by existing contracts. The net book value is compared to the ceiling on a quarterly basis. The excess, if any, of the net book value above the ceiling is required to be written off as an expense. Under SEC full cost accounting rules, any write-off recorded may not be reversed even if higher oil and gas prices increase the ceiling applicable to future periods. Future price decreases could result in reductions in the carrying value of such assets and an equivalent charge to earnings. AUTHORIZED PREFERRED STOCK. The Company's Articles of Incorporation authorize the issuance of up to 10,000,000 shares of Cumulative Preferred Stock, par value $1.00 per share, and up to 10,000,000 shares of Non-Cumulative Preferred Stock, par value $1.00 per share. The Board of Directors of the Company has the authority to divide the two classes of Preferred Stock into series and to fix and determine the relative rights and preferences of the shares of any such series. Such preferences could include, among other things, the establishment of dividends which must be paid prior to the declaration or payment of dividends or other distributions (including share repurchases) with respect to Common Stock. Moreover, other terms established by the Board of Directors, such as voting or liquidation rights, could adversely affect the rights of holders of Common Stock. In addition, the ability of the Board of Directors to issue Preferred Stock could impede or deter unsolicited tender offers or takeover proposals regarding the Company. FUTURE DILUTION. As of the date of this Prospectus, there were warrants and options outstanding to purchase 879,150 shares of the Common Stock of the Company representing 6.7% of its then outstanding shares of Common Stock. Of the total warrants and options outstanding, 205,000 are exercisable at $2.00 per share, 163,400 are exercisable at $2.75 per share, 1,250 are exercisable at $3.52 per share, 80,000 are exercisable at $3.63 per share, 15,000 are exercisable at $3.69 per share, 105,000 are exercisable at $4.25 per share, 50,000 are exercisable at $4.31 per share, 56,000 are exercisable at $4.38 per share, 20,000 are exercisable at $4.44 per share, 17,500 are exercisable at $4.56 per share, 90,000 are exercisable at $4.63 per share, 61,000 are exercisable at $4.75 per share, and 15,000 are exercisable at $5.13 per share. These options and warrants enable the holder to profit from a rise in the market value of the Common Stock with potential dilution to the existing holders of Common Stock. The existence of these warrants and options, representing an overhanging obligation to sell additional Common Stock at prices that may be below the then current market price of the Common Stock, could inhibit the ability of the Company to obtain new equity because of reluctance by potential equity holders to absorb potential dilution to the value of their shares. - 4 - -----END PRIVACY-ENHANCED MESSAGE-----