UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
| x | QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period endedSeptember 30, 2003
OR
| ¨ | TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File Number 1-7796
TIPPERARY CORPORATION
(Exact name of registrant as specified in its charter)
| Texas | 75-1236955 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
633 Seventeenth Street, Suite 1550 Denver, Colorado | 80202 | |
| (Address of principal executive offices) | (Zip Code) |
(303) 293-9379
(Issuer’s telephone number)
Check whether the issuer (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act of 1934 during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yesx No¨
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
Yes¨Nox
State the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
| Class | Outstanding at November 14, 2003 | |||
| Common Stock, $.02 par value | 39,221,489 shares |
TIPPERARY CORPORATION AND SUBSIDIARIES
TIPPERARY CORPORATION AND SUBSIDIARIES
(in thousands, except share data)
(unaudited)
| September 30 2003 | December 31 2002 | |||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 1,066 | 1,725 | |||||
Restricted cash | — | 546 | ||||||
Receivables | 2,276 | 1,863 | ||||||
Other current assets | 744 | 290 | ||||||
Total current assets | 4,086 | 4,424 | ||||||
Property, plant and equipment, at cost: | ||||||||
Oil and gas properties, full cost method | 105,907 | 75,395 | ||||||
Other property and equipment | 4,467 | 3,827 | ||||||
| 110,374 | 79,222 | |||||||
Less accumulated depreciation, depletion and amortization | (7,208 | ) | (4,882 | ) | ||||
Property, plant and equipment, net | 103,166 | 74,340 | ||||||
Deferred loan costs | 385 | 5,751 | ||||||
Other noncurrent assets | 467 | 238 | ||||||
| $ | 108,104 | $ | 84,753 | |||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
Current liabilities: | ||||||||
Current portion of long-term debt | 5,470 | — | ||||||
Accounts payable | 3,412 | 1,384 | ||||||
Accrued liabilities | 2,247 | 1,970 | ||||||
Royalties payable | 89 | 130 | ||||||
Total current liabilities | 11,218 | 3,484 | ||||||
Long-term debt | 52,747 | 27,899 | ||||||
Long-term asset retirement obligation | 284 | — | ||||||
Minority interest | 553 | 603 | ||||||
Commitments and contingencies (Note 5) | ||||||||
Stockholders’ equity | ||||||||
Preferred stock: | ||||||||
Cumulative; par value $1.00; 10,000,000 shares authorized; none issued | — | — | ||||||
Non-cumulative, par value $1.00; 10,000,000 shares authorized; none issued | — | — | ||||||
Common stock; par value $.02; 50,000,000 shares authorized; 39,231,087 shares issued and 39,221,489 shares outstanding | 785 | 785 | ||||||
Capital in excess of par value | 149,970 | 149,953 | ||||||
Accumulated deficit | (111,091 | ) | (97,946 | ) | ||||
Accumulated other comprehensive income | 3,663 | — | ||||||
Treasury stock, at cost; 9,598 shares | (25 | ) | (25 | ) | ||||
Total stockholders’ equity | 43,302 | 52,767 | ||||||
| $ | 108,104 | $ | 84,753 | |||||
See accompanying notes to consolidated financial statements.
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TIPPERARY CORPORATION AND SUBSIDIARIES
Consolidated Statements of Operations
(in thousands, except per share data)
(unaudited)
| Three months ended | Nine months ended | |||||||||||||||
| September 30 | September 30 | |||||||||||||||
| 2003 | 2002 | 2003 | 2002 | |||||||||||||
Revenues | $ | 1,714 | $ | 1,092 | $ | 4,764 | $ | 3,696 | ||||||||
Costs and expenses: | ||||||||||||||||
Operating | 1,257 | 800 | 3,325 | 2,108 | ||||||||||||
Depreciation, depletion and amortization | 455 | 289 | 1,161 | 1,124 | ||||||||||||
Gain on sale of assets | — | — | — | (766 | ) | |||||||||||
Write-down of oil and gas properties | 165 | — | 2,386 | — | ||||||||||||
Asset retirement obligation accretion | 6 | — | 18 | — | ||||||||||||
Recovery of prepaid drilling costs | — | (282 | ) | — | (282 | ) | ||||||||||
General and administrative | 1,353 | 1,106 | 4,165 | 3,692 | ||||||||||||
Total costs and expenses | 3,236 | 1,913 | 11,055 | 5,876 | ||||||||||||
Operating loss | (1,522 | ) | (821 | ) | (6,291 | ) | (2,180 | ) | ||||||||
Other income (expense): | ||||||||||||||||
Interest income | 13 | 16 | 35 | 64 | ||||||||||||
Write-off of deferred loan costs | (5,069 | ) | — | (5,069 | ) | — | ||||||||||
Interest expense | (1,403 | ) | (797 | ) | (3,883 | ) | (2,191 | ) | ||||||||
Other income | — | — | — | 70 | ||||||||||||
Foreign currency exchange gain (loss) | (1,053 | ) | (35 | ) | 2,060 | 19 | ||||||||||
Total other income (expense) | (7,512 | ) | (816 | ) | (6,857 | ) | (2,038 | ) | ||||||||
Loss before income taxes | (9,034 | ) | (1,637 | ) | (13,148 | ) | (4,218 | ) | ||||||||
Income tax benefit | — | — | — | — | ||||||||||||
Loss before minority interest and cumulative effect of accounting change | (9,034 | ) | (1,637 | ) | (13,148 | ) | (4,218 | ) | ||||||||
Minority interest in loss of subsidiary | 230 | 11 | 49 | 72 | ||||||||||||
Loss before cumulative effect of accounting change | (8,804 | ) | (1,626 | ) | (13,099 | ) | (4,146 | ) | ||||||||
Cumulative effect of accounting change | — | — | (46 | ) | — | |||||||||||
Net loss | $ | (8,804 | ) | $ | (1,626 | ) | $ | (13,145 | ) | $ | (4,146 | ) | ||||
Net loss per share | ||||||||||||||||
Basic and diluted | $ | (.22 | ) | $ | (.04 | ) | $ | (.34 | ) | $ | (.11 | ) | ||||
Weighted average shares outstanding | ||||||||||||||||
Basic and diluted | 39,221 | 39,221 | 39,221 | 39,090 | ||||||||||||
See accompanying notes to consolidated financial statements.
2
TIPPERARY CORPORATION AND SUBSIDIARIES
Consolidated Statements of Cash Flows
(in thousands)
(unaudited)
| Nine months ended September 30 | ||||||||
| 2003 | 2002 | |||||||
Cash flows from operating activities: | ||||||||
Net loss | $ | (13,145 | ) | $ | (4,146 | ) | ||
Adjustments to reconcile net loss to net cash used in operating activities: | ||||||||
Depreciation, depletion and amortization | 1,161 | 1,124 | ||||||
Amortization and write-off of deferred loan costs | 5,770 | 1,118 | ||||||
Warrants granted for services | 6 | 7 | ||||||
Minority interest in loss of subsidiary | (49 | ) | (72 | ) | ||||
Foreign currency exchange gain | (2,070 | ) | — | |||||
Gain on sale of assets | — | (766 | ) | |||||
Asset retirement obligation accretion | 18 | — | ||||||
Cumulative effect of accounting change | 46 | — | ||||||
Write-down of oil and gas properties | 2,386 | — | ||||||
Changes in current assets and current liabilities: | ||||||||
(Increase) decrease in receivables | (178 | ) | 54 | |||||
(Increase) decrease in other current assets | (395 | ) | 55 | |||||
Increase (decrease) in accounts payable and accrued liabilities | 823 | (70 | ) | |||||
Decrease in royalties payable | (41 | ) | (93 | ) | ||||
Net cash used in operating activities | (5,668 | ) | (2,789 | ) | ||||
Cash flows from investing activities: | ||||||||
Proceeds from asset sales | 2,912 | 5,623 | ||||||
Capital expenditures | (26,340 | ) | (19,973 | ) | ||||
Net cash used in investing activities | (23,428 | ) | (14,350 | ) | ||||
Cash flows from financing activities: | ||||||||
Proceeds from borrowings | 55,512 | 11,000 | ||||||
Principal repayments | (27,129 | ) | (315 | ) | ||||
Decrease in restricted cash | 546 | 1,086 | ||||||
Payments for deferred loan costs | (362 | ) | (567 | ) | ||||
Net cash provided by financing activities | 28,567 | 11,204 | ||||||
Effect of exchange rate changes on cash | (130 | ) | — | |||||
Net increase (decrease) in cash and cash equivalents | (659 | ) | (5,935 | ) | ||||
Cash and cash equivalents at beginning of period | 1,725 | 9,415 | ||||||
Cash and cash equivalents at end of period | $ | 1,066 | $ | 3,480 | ||||
Supplemental disclosure of cash flow information: | ||||||||
Cash paid during the period for: | ||||||||
Interest | $ | 2,860 | $ | 1,502 | ||||
Income taxes | $ | — | $ | — | ||||
Non-cash investing and financing activities: | ||||||||
Issuance of stock to acquire assets | $ | — | $ | 450 | ||||
See accompanying notes to consolidated financial statements.
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TIPPERARY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
In the opinion of management, the accompanying unaudited consolidated financial statements reflect all adjustments, consisting only of normal recurring adjustments, which are necessary for a fair presentation of the financial position of Tipperary Corporation and its subsidiaries (the “Company”) at September 30, 2003, and the results of its operations for the three-month and nine-month periods ended September 30, 2003 and 2002 and its cash flows for the nine-month periods ended September 30, 2003 and 2002. The consolidated financial statements include the accounts of Tipperary Corporation and its wholly-owned subsidiaries, Tipperary Oil and Gas Corporation and Burro Pipeline Corporation, and its 90%-owned subsidiary, Tipperary Oil and Gas (Australia) Pty Ltd (“TOGA”). All intercompany balances have been eliminated. The accounting policies followed by the Company are included in Note 1 to the Consolidated Financial Statements in its Annual Report on Form 10-KSB for the year ended December 31, 2002. These financial statements should be read in conjunction with the 2002 Form 10-KSB and with the Form 10-Q dated March 31, 2003 and June 30, 2003.
Impact of New Accounting Pronouncements
In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity” (“SFAS 150”). SFAS 150 establishes standards on the classification and measurement of certain financial instruments with characteristics of both liabilities and equity. The provisions of SFAS 150 are effective for financial instruments entered into or modified after May 31, 2003, and generally to all other instruments that exist as of the beginning of the first interim financial reporting period beginning after June 15, 2003. The adoption of SFAS 150 does not have a material effect on the Company’s consolidated financial statements.
In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), which provides accounting requirements for retirement obligations associated with tangible long-lived assets, including the timing of liability recognition, initial measurement of the liability, allocation of asset retirement costs to expense, subsequent measurement of the liability, and financial statement disclosures. SFAS 143 requires that asset retirement costs be capitalized along with the cost of the related long-lived asset. The asset retirement costs should then be allocated to expense using a systematic and rational method. The Company has determined that it has asset retirement costs associated with wells drilled in Australia and the United States. The Company also expects to incur retirement costs to dismantle two gas compression plant facilities located in Australia. The Company adopted SFAS 143 on January 1, 2003, which resulted in an increase in property, plant and equipment of $134,000 and establishment of an asset retirement obligation of $180,000. The transition adjustment of $46,000 was reported as a cumulative effect of accounting change. If the Company had applied the provisions of SFAS 143 as of January 1, 2002, the Company’s asset retirement obligation would have been $145,000 at January 1, 2002. The Company’s pro forma net loss would have been $1.631 million and $4.160 million for the three and nine months ended September 30, 2002 assuming SFAS 143 had been adopted on January 1, 2002. As a result of adopting SFAS 143, the estimated asset retirement obligation accretion for 2003 is expected to be approximately $27,400.
Beginning asset retirement obligation at January 1, 2003 | $ | 180,000 | |
Asset retirement obligation accretion | 18,000 | ||
Asset retirement obligation additions | 86,000 | ||
Ending asset retirement obligation at September 30, 2003 | $ | 284,000 | |
In June 2001, the FASB issued SFAS No. 141, “Business Combinations” (“SFAS 141”) and SFAS No. 142, “Goodwill and Intangible Assets” (“SFAS 142”). SFAS 141 and 142 became effective on July 1, 2001 and January 1, 2002, respectively. SFAS 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. Additionally, SFAS 141 requires companies to disaggregate and report separately from goodwill certain
4
intangible assets. SFAS 142 establishes new guidelines for accounting for goodwill and other intangible assets. Under SFAS 142, goodwill and certain other intangible assets are not amortized, but rather are reviewed annually for impairment. One interpretation being considered relative to these standards is that oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves for both undeveloped and developed leaseholds should be classified separately from oil and gas properties, as intangible assets on the Company’s consolidated balance sheets. In addition, the disclosures required by SFAS 141 and 142 relative to intangibles would be included in the notes to financial statements. Historically, the Company, like many other oil and gas companies, has included these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves as part of oil and gas properties, even after SFAS 141 and 142 became effective.
As applied to companies that have adopted full cost accounting for oil and gas activities, the Company understands that this interpretation of SFAS 141 and 142 would only affect the Company’s balance sheets classification of proved oil and gas leaseholds acquired after June 30, 2001 and the Company’s unproved oil and gas leaseholds. The Company’s results of operations and cash flows would not be affected, since these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves would continue to be amortized in accordance with full cost accounting rules.
At September 30, 2003 and December 31, 2002, the Company had undeveloped leaseholds of approximately $3.2 million and $3.0 million, respectively, that would be classified on the consolidated balance sheet as “intangible undeveloped leaseholds” and no amounts that would be classified as “intangible developed leaseholds,” if the Company applied the interpretations currently being discussed.
The Company will continue to classify its oil and gas mineral rights held under lease and other contractual rights representing the right to extract such reserves as tangible oil and gas properties until further guidance is provided.
Stock-Based Compensation
At September 30, 2003, the Company had two stock-based employee option plans issued to directors and employees and warrants granted to Company directors and employees and to non-employees for services. The Company has chosen to continue to account for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees”, (“APB 25”) and has applied the disclosure provisions of SFAS 123 “Accounting for Stock-Based Compensation” (“SFAS 123”)and SFAS 148 “Accounting for Stock-Based Compensation – Transition and Disclosure – An Amendment of SFAS 123”. Accordingly, compensation cost for fixed stock options and warrants is measured as the excess, if any, of the quoted market price of the Company’s stock at the date of the grant over the amount a director or employee must pay to acquire the stock. Pro forma disclosures as if the Company had adopted the cost recognition provisions of SFAS 123 are presented below.
| Three months ended September 30 | Nine months ended September 30 | |||||||||||||||
| 2003 | 2002 | 2003 | 2002 | |||||||||||||
Net loss as reported | $ | (8,804,000 | ) | $ | (1,626,000 | ) | $ | (13,145,000 | ) | $ | (4,146,000 | ) | ||||
Add: | ||||||||||||||||
Total compensation cost included in reported net loss, net of tax | — | — | — | — | ||||||||||||
Deduct: | ||||||||||||||||
Total compensation cost determined under fair value based method for all awards, net of tax | (37,000 | ) | (60,000 | ) | (110,000 | ) | (181,000 | ) | ||||||||
Pro forma net loss | $ | (8,841,000 | ) | $ | (1,686,000 | ) | $ | (13,255,000 | ) | $ | (4,327,000 | ) | ||||
Loss per share | ||||||||||||||||
Basic and diluted—as reported | $ | (.22 | ) | $ | (.04 | ) | $ | (.34 | ) | $ | (.11 | ) | ||||
Basic and diluted—pro forma | $ | (.23 | ) | $ | (.04 | ) | $ | (.34 | ) | $ | (.11 | ) | ||||
5
Ceiling Test Write-Down
The Company accounts for its oil and gas properties using the full cost method. Under this method, the Company is required to record a permanent impairment provision if the net book value of its oil and gas properties less related deferred taxes exceeds a ceiling value equal to the present value of the future cash inflows from proved reserves, discounted at 10% plus the cost of unproved properties not being amortized and the lower of cost or fair value of unproved properties being amortized, less the related tax effects. The ceiling test is computed by country and at the end of each quarter. The oil and gas prices used in calculating future cash inflows in the United States are based on the market price on the last day of the accounting period and in Australia are based on long term contract prices. Oil and gas prices are generally volatile; and if the market prices at a period end date have decreased, the Company may have to record an impairment. A loss may also be generated by the transfer of significant early stage exploratory costs to the pool of amortizable costs, which is subject to the ceiling test. These losses typically occur when significant costs are transferred to the pool of amortizable costs, as a result of an unsuccessful project without commercially productive oil and gas production. The Company recorded a ceiling test write-down of $2.2 million at June 30, 2003 and $200,000 at September 30, 2003. The write-downs are the direct result of extended production testing and further drilling that caused the Company to eliminate the proved reserves previously attributed to its Nine Mile properties in the United States.
Gas Imbalances
In natural gas production operations, joint owners sometimes sell more or less than the production volumes to which they are entitled based on their revenue ownership interest. The joint operating agreement includes gas balancing provisions to govern production allocations in this situation. The Company records a natural gas imbalance in other liabilities if any excess takes of natural gas exceed its remaining proved reserves for the property. As of September 30, 2003, the Company had taken and sold more than its share of natural gas volumes produced from the Comet Ridge project, and was overproduced by approximately 1,820 MMcf. Based on the average price of $1.43 per Mcf received during the first nine months of 2003 from these sales, this represents $2.6 million in gas revenues. No liability has been recorded for the excess volumes taken as they do not exceed the Company’s share of remaining proved reserves. Under the terms of the gas balancing agreement, the Company may be required to reduce the monthly volumes it sells by up to 50% of its entitled share of sales, to enable underproduced parties to sell more than their entitled share of the gas sales and cure the imbalance. Any reduction in monthly volumes will negatively affect the Company’s revenues, and operating expenses will not decline proportionately.
Foreign Currency Translation
Effective April 1, 2003, the Company changed the functional currency of its Australian subsidiary (“TOGA”) from the U.S. dollar to the Australian dollar. In April 2003, the Company began borrowing Australian dollars under its new debt agreement with STEL (Note 2 to the Consolidated Financial Statements). That fact, combined with TOGA’s assumption of operations of the Comet Ridge project and increased gas sales from the project, results in substantially all of TOGA’s transactions being denominated in the Australian dollar. As the functional currency is the local currency, the current rate method is used to translate Australian dollar financial statements into U.S. dollars for TOGA. All assets and liabilities are translated using current exchange rates, while revenues and expenses are translated at rates in existence when the transactions occurred. The translation adjustment that results from using varying rates in the translation process is reported as a component of other comprehensive income and is accumulated and reported as a separate line item in stockholders’ equity in the Company’s consolidated financial statements.
As a result of the change in functional currency effective April 1, 2003, the Company recorded an initial foreign currency translation adjustment of $249,000. The cumulative foreign currency translation adjustment as of September 30, 2003 totaled $3,663,000. In accordance with SFAS No. 52, “Foreign Currency Translation” (“SFAS 52”), during the three and nine months ended September 30, 2003, the Company recognized a foreign currency exchange gain (loss) of ($1,053,000) and $2,060,000, respectively, related to intercompany debt. Substantially all of this foreign exchange gain (loss) relates to intercompany debt TOGA owed Tipperary Corporation prior to August 15, 2003. As described in Note 2 to the Consolidated Financial Statements, the non-permanent portion of intercompany debt was substantially reduced on August 15, 2003. This reduction is expected to substantially reduce future foreign currency gains and losses.
6
Liquidity and Operations
The Company anticipates funding operations and domestic and Australian non-discretionary exploratory capital expenditures for the remainder of 2003 using (a) net gas revenues; (b) funds remaining (approximately $3.9 million) under the $25 million credit facilities from Slough Trading Estates Limited (“STEL”), a UK company and wholly-owned subsidiary of Slough Estates plc and parent of Slough Estates USA Inc. (“Slough”), which owns 61.3% of the Company’s outstanding common stock (See Note 2 to the Consolidated Financial Statements); (c) approximately $400,000 of net proceeds from the sale of certain oil and gas properties; and (d) approximately $4 million in additional loans from STEL or Slough.
In order to fund discretionary capital expenditures in 2003 in excess of these cash resources and to fund capital expenditures beyond 2003, the Company will require alternative sources of capital. Potential additional sources of funding are expected to include additional debt financings and asset sales. The Company is currently in formal discussions with a group of banks interested in providing debt financing to TOGA. The Company is seeking the financing to be (a) available in the fourth quarter of 2003, (b) secured by the Company’s consolidated interests in the Comet Ridge project in Queensland, Australia, and (c) partially guaranteed by Slough Estates plc, STEL’s UK parent. If obtained, the Company anticipates that the financing would be used to repay the Company’s long-term debt denominated in Australian dollars with STEL and (to the extent available) fund Comet Ridge development in 2004, 2005 and 2006.
Although the Company anticipates this financing will occur, uncertainties and assumptions that are difficult to predict with regard to timing, likelihood and degree of occurrence may affect the Company’s ability to secure such financing.
On an ongoing basis, the Company seeks to sell interests in its exploration acreage inventory in the United States and retain carried working interests. In the event of such sales, the Company generates cash to reduce its investment in individual projects and fund exploration costs. However, in the event that sufficient capital cannot be generated from property sales or other funding cannot be obtained, the Company will be required to curtail planned expenditures and may have to sell additional acreage and/or relinquish acreage at prices that are not favorable to the Company.
NOTE 2—RELATED PARTY TRANSACTIONS
At September 30, 2003, the Company owed Slough and STEL approximately $58 million as shown in the following table:
| Lendor | Borrower | Loan Initiated | USD Current Balance | Loan Denomination | Due Date | Annual Rate | Purpose | |||||||
STEL | TOGA | AUG 2003 | $29 Million | AUD | FEB 2005 | 13% | Retire debt and purchase royalty | |||||||
STEL | TOGA | MAR 2003 | $17 million | AUD | APR 2012 | 13% | Exploration & development | |||||||
STEL | Tipperary | MAR 2003 | $6.5 million | USD | APR 2012 | 13% | General corporate | |||||||
Slough | Tipperary | JUL 2002 | $4 million | USD | APR 2004 | 4.6% | General corporate | |||||||
Slough | Tipperary | JAN 2001 | $1.5 million | USD | JUL 2004 | 10% | Purchase drilling rig | |||||||
On August 15, 2003, TOGA borrowed $29 million from STEL for the sole purpose of paying off the $22 million long-term debt owed TCW Asset Management Company (“TCW”) and to substantially fund the $7.7 million repurchase of the 6% overriding royalty held by TCW on the Company’s Comet Ridge properties. As a result of retiring the TCW debt, TOGA’s intercompany debt with the Company was reduced by approximately $22 million.
The Company recorded deferred financing costs of approximately $6,800,000 in connection with the TCW credit agreement, which was the then present value (discounted at 15%) of the overriding royalty conveyed to TCW. This cost reduced the book value of the Company’s oil and gas properties in Australia and was amortized as interest expense over the life of the loan. Deferred loan costs also include approximately $1,683,000 of other costs incurred to obtain the TCW financing, which were likewise amortized as interest expense over the life of the loan. The remaining unamortized deferred loan costs of $5.1 million were expensed in full in the third quarter of 2003 with the retirement of the TCW debt.
In March 2003, the Company entered into two credit facility agreements with STEL allowing the Company to borrow on an unsecured basis up to $25 million from STEL. The Company may repay the loans in whole or in part without prepayment penalties. STEL may demand repayment prior to the maturity date provided that STEL gives 18-month notice.
In January 2001, Slough advanced the Company $2.5 million to finance the purchase of a drilling rig to be used in Australia. Although there are no mandatory principal payments prior to the maturity date, the Company is obligated to reduce the principal balance by the amount of monthly rents received from the drilling contractor.
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NOTE 3—LONG-TERM DEBT—UNRELATED PARTY
Through August 15, 2003, the Company was a party to an amended and restated Credit Agreement with TCW with a principal balance of $22 million, which was used for development of the Comet Ridge project. As explained in Note 2 to the Consolidated Financial Statements, the Company has repaid this loan.
NOTE 4 – LOSS PER SHARE
The following table sets forth the computation of basic and diluted loss per share (“EPS”) (in thousands except per share data):
| Three months ended September 30 | Nine months ended September 30 | |||||||||||||||
| 2003 | 2002 | 2003 | 2002 | |||||||||||||
Numerator: | ||||||||||||||||
Net loss | $ | (8,804 | ) | $ | (1,626 | ) | $ | (13,145 | ) | $ | (4,146 | ) | ||||
Denominator: | ||||||||||||||||
Weighted average shares outstanding | 39,221 | 39,221 | 39,221 | 39,090 | ||||||||||||
Effect of dilutive securities: | ||||||||||||||||
Assumed conversion of dilutive options and warrants | — | — | — | — | ||||||||||||
Weighted average shares and dilutive potential common shares | 39,221 | 39,221 | 39,221 | 39,090 | ||||||||||||
Basic and diluted loss per share | $ | (.22 | ) | $ | (.04 | ) | $ | (.34 | ) | $ | (.11 | ) | ||||
Number of shares of potentially dilutive common stock from the exercise of options and warrants not included in EPS because they would have been antidilutive | 494 | 82 | 212 | 60 | ||||||||||||
Total common stock options and warrants that could potentially dilute basic EPS in future periods | 3,573 | 3,488 | 3,573 | 3,488 | ||||||||||||
NOTE 5—COMMITMENTS AND CONTINGENCIES
The Company, TOGA and two unaffiliated working interest owners are plaintiffs in a lawsuit filed in 1998, styledTipperary Corporation and Tipperary Oil & Gas (Australia) Pty Ltd v. Tri-Star Petroleum Company, James H. Butler, Sr., and James H. Butler, Jr., Cause No. CV42,265, District Court of Midland County, Texas involving the Comet Ridge project. The plaintiffs allege, among other matters, that Tri-Star and/or the individual defendants failed to operate the project in a good and workmanlike manner and committed various other breaches of a joint operating contract, breached a previous mediation agreement, committed certain breaches of fiduciary and other duties owed to the plaintiffs, and committed fraud in connection with the project. Tri-Star answered the allegations, and filed a counterclaim alleging tortious interference with respect to the contracts, the authority to prospect covering the project and contractual relationships with vendors; commercial disparagement; foreclosure of operator’s lien and alternatively forfeiture of undeveloped acreage; unjust enrichment and declaratory relief. As of February 2001, the District Court enjoined Tri-Star from asserting any forfeiture claims based upon events prior to that date. In March 2002, the court entered its Writ of Temporary Injunction (the “Injunction”) to enforce the votes of a majority-in-interest of the parties under the joint operating agreement to remove Tri-Star as operator and replace it with TOGA, and TOGA did succeed Tri-Star as operator on March 22, 2002. All available appeals have been exhausted. Therefore, TOGA will continue as operator of the Comet Ridge Project at least through the conclusion of a trial on the merits, and thereafter if successful at trial.
In June 2002, the District Court ruled as unenforceable the arbitration provisions of the existing mediation agreement between the parties. The Eighth District Court of Appeals affirmed the action of the District Court, and Tri-Star filed a Petition for Review in the Supreme Court of Texas. The Company has filed a response to the Petition for Review. The
8
Supreme Court has discretion to either hear, or refuse to hear, the appeal, and no decision has yet been announced. Although pre-trial discovery is proceeding, the pending appeal continues to delay the trial on the merits, and a new trial date will not be set before all appellate proceedings are resolved.
In August 2003, the District Court heard the Company’s Motion to Compel Compliance with Amended Writ of Temporary Injunction. On October 1, 2003, the Court signed an Order finding that Tri-Star willfully disobeyed the Injunction, ordering Tri-Star to cooperate with the Operator and, among other things, to execute a power of attorney to allow the Company to deal directly with the Department of Natural Resources and Mines in Queensland, and the surface owners, on matters pertaining to the Comet Ridge Project. In addition, the Court has indicated it will conduct a show cause hearing to determine whether sanctions for Tri-Star’s past violations of the Injunction, and conditional sanctions to deter future violations, should be imposed.
Prior to taking over operations, the Company and other plaintiffs sent payments on disputed Tri-Star billings to the Registry of the Court. The amount now held in the Registry of the Court due to these payments and accrued interest is $1.3 million. The Company and other plaintiffs have filed a Motion to Withdraw, seeking return of the $1.3 million held in the Registry of the Court, and that the Motion will be heard in the near term. Upon return of the $1.3 million from the Court, the Company expects to return approximately $200,000 to Comet Ridge partners and will record $1.1 million as a recovery of prepaid drilling costs.
To the extent the Court eventually finds that all or a portion of the disputed Tri-Star billings were inappropriate, Tri-Star would owe up to $1.2 million additional monies to the Company. The additional sums, if the full $1.2 million is received, would be recorded as a $1 million recovery of capital costs and a $200,000 recovery of operating expenses. It is the Company’s opinion that the May 29, 2003 Appellate Court affirmation of the lower court’s decision strongly supports the Company’s position that the billings were inappropriate.
The Company may be entitled to additional damages based upon Tri-Star’s billing practices and handling of the arbitration process if the June 21, 2002 ruling of the District Court is upheld on final appeal.
NOTE 6—OPERATIONS BY GEOGRAPHIC AREA
The Company has one operating and reporting segment—oil and gas exploration, development and production—in the United States and Australia. Information about the Company’s operations by geographic area is shown below (in thousands):
| Australia | United States | Total | ||||||||
Operating revenue for the three months ended September 30, 2003 | $ | 1,710 | $ | 4 | $ | 1,714 | ||||
Operating revenue for the three months ended September 30, 2002 | $ | 1,227 | $ | (135 | ) | $ | 1,092 | |||
Operating revenue for the nine months ended September 30, 2003 | $ | 4,753 | $ | 11 | $ | 4,764 | ||||
Operating revenue for the nine months ended September 30, 2002 | $ | 3,267 | $ | 429 | $ | 3,696 | ||||
Property, plant and equipment, net, at September 30, 2003 | $ | 96,868 | $ | 6,298 | $ | 103,166 | ||||
Property, plant and equipment, net, at December 31, 2002 | $ | 66,881 | $ | 7,459 | $ | 74,340 | ||||
9
NOTE 7– PROPERTY, PLANT AND EQUIPMENT
A summary of property, plant and equipment follows:
| September 30 2003 | December 31 2002 | |||||||
Evaluated oil and gas properties: | ||||||||
Evaluated Australian properties | $ | 93,467 | $ | 64,469 | ||||
Evaluated domestic properties | 12 | 986 | ||||||
Unevaluated oil and gas properties: | ||||||||
Unevaluated Australian properties | 6,301 | 3,619 | ||||||
Unevaluated domestic properties | 6,127 | 6,321 | ||||||
Oil and gas properties | 105,907 | 75,395 | ||||||
Other property and equipment | 4,467 | 3,827 | ||||||
| 110,374 | 79,222 | |||||||
Less accumulated depreciation, depletion and amortization | (7,208 | ) | (4,882 | ) | ||||
Property, plant and equipment, net | $ | 103,166 | $ | 74,340 | ||||
On August 15, 2003 the Company purchased TCW’s royalty interest in the Comet Ridge Project for $7.7 million. This amount is included in evaluated Australian properties.
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Item 2.Management’s Discussion and Analysis
Information within this report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are based on management’s beliefs, assumptions, current expectations, estimates and projections about the oil and gas industry, the world economy and about the Company itself. Words such as “may,” “will,” “expect,” “anticipate,” “estimate” or “continue,” or comparable words are intended to identify such forward-looking statements. In addition, all statements other than statements of historical facts that address activities that the Company expects or anticipates will or may occur in the future are forward-looking statements. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict with regard to timing, extent, likelihood and degree of occurrence. Therefore, actual results and outcomes may materially differ from what may be expressed or forecasted in such forward-looking statements. Furthermore, the Company undertakes no obligation to update, amend or clarify forward-looking statements, whether as a result of new information, future events or otherwise. Readers are encouraged to read the SEC filings of the Company, particularly its Form 10-KSB for the year ended December 31, 2002, for meaningful cautionary language disclosing why actual results may vary materially from those anticipated by management.
Overview
Australia
The Company’s activities in Australia are conducted substantially through the Company’s 90%-owned Australian subsidiary, Tipperary Oil & Gas (Australia) Pty Ltd (“TOGA”). As of September 30, 2003, the Company owned a 73% capital interest and a 69.52% pre-royalty revenue interest in the Comet Ridge project in Queensland, Australia. This project comprises approximately 1,058,000 acres in the Bowen Basin and includes five petroleum leases covering approximately 278,000 acres, Authority to Prospect (“ATP”) 526 covering approximately 687,000 acres, and ATP 653 covering approximately 93,000 acres.
An ATP allows the holder to undertake a range of exploration activities, including geophysical surveys, field mapping and exploratory drilling. Each ATP requires the expenditure of an amount of exploration costs as determined by Queensland’s Department of Natural Resources and Mines (“Queensland DNRM”) and is subject to renewal every four years. Once a petroleum resource is identified, the holder of an ATP may apply for a petroleum lease, which provides the lessee with the ability to conduct additional exploration, development and production activities.
As of November 1, 2003, the Company has met its 2003 expenditure requirements for ATP 526 and ATP 653. ATP 526 and 653 have initial terms expiring on October 31, 2004 and September 30, 2006, respectively.
The following table summarizes field development progress on the Comet Ridge project. The Company substantially completed the installation of a second compression plant facility in October 2003. In November 2003 the Company expects to begin compressing gas utilizing the new facility, providing for the field a current sales capacity of approximately 30 MMcf per day. The field has an approximate additional 11 MMcf per day of sales capacity from wells not yet connected to the compressor facilities. Upon connection of these wells, the field would have total sales capacity of 41 MMcf per day. Actual field sales at September 30, 2003 were 14 MMcf per day. During September 2003 the project’s main purchaser of gas reduced nominations by approximately 3 MMcf per day. In November 2003 nominations increased and total sales volumes are currently 16 MMcf per day. The Company is in discussions with its major customer and various others for short-term and long-term contracts for the sale of additional gas from the Comet Ridge field. The Company is equipping wells to allow future production to more closely match sales demand so as to minimize flaring of gas at the wells.
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Comet Ridge Operations Review:
| September 30 2003 | June 30 2003 | March 31 2003 | December 31 2002 | |||||
Well Status (Number of Gross Wells) | ||||||||
Selling | 36 | 36 | 34 | 33 | ||||
Dewatering or Shut-in | 41 | 28 | 26 | 26 | ||||
Producing | 77 | 64 | 60 | 59 | ||||
Being Evaluated | 13 | 13 | 11 | 10 | ||||
To be Plugged and Abandoned | 2 | 2 | 3 | 3 | ||||
Plugged and Abandoned | 2 | 1 | 1 | 1 | ||||
Drilled | 94 | 80 | 75 | 73 | ||||
Gross Daily Volumes (MMcf) | ||||||||
Sold | 14 | 17 | 17 | 19 | ||||
Flared | 4 | 10 | 7 | 4 | ||||
Used for Compression Fuel | 2 | 2 | 2 | 2 | ||||
Produced | 20 | 29 | 26 | 25 | ||||
The Company has drilled approximately 20 wells on the Comet Ridge project during the first nine months of 2003. The Company plans to drill approximately 10 more wells in the remainder of 2003. Of the wells drilled or to be drilled in 2003, approximately nine wells are considered exploratory wells. The remaining wells drilled are in development locations and are expected to contribute to gas sales volumes after the gathering system is expanded to include these wells and new gas sales contracts are executed. The drilling was substantially funded under a $25 million borrowing facility entered into in March 2003 with Slough Trading Estates Limited, a United Kingdom company which is the parent company of the Company’s majority shareholder. See Note 2 to the Consolidated Financial Statements.
During the first nine months of 2003, the Company sold 100% of the gas for which it had sales contracts in Australia under two contracts with ENERGEX Retail Pty Ltd (“ENERGEX”), an unaffiliated customer. The first contract has delivery requirements of up to approximately 5,500 Mcf of gas per day through December 2003. A second five-year contract, entered into with ENERGEX effective June 1, 2000, has delivery requirements of up to approximately 15,000 Mcf of gas per day. In December 2002, the Company entered into a gas sales agreement with Origin Energy Retail Limited (“OERL”), a subsidiary of Origin Energy Limited, to supply approximately 9 Bcf per year (i.e., approximately 25,000 Mcf of gas per day) net to the Company’s interests, for thirteen years beginning May 2007. Origin Energy Limited is a large Australian integrated energy company which, through subsidiaries, owns nearly 24% of the Comet Ridge project.
Effective June 30, 2003, the Company extended the agreement with Queensland Fertilizer Assets Limited (“QFAL”) until December 31, 2003 to supply 260 Bcf of gas over a 20-year period beginning in mid 2006 to a fertilizer plant QFAL is proposing to construct in southeastern Queensland. Prior to December 31, 2003, QFAL must obtain commitments to finance construction of the fertilizer plant or the Company will be released from its gas supply commitment unless the agreement is extended. The Company believes it has reasonable certainty, based upon the gas market in Eastern Australia, that this production can be sold in the market, if not sold to QFAL.
In addition to the interest in the Comet Ridge project, TOGA holds a 100% interest in ATP’s 655 and 675 covering approximately 278,000 acres in total as of September 30, 2003. ATP’s 655 and 675 have initial terms expiring on October 31, 2003 and February 29, 2004, respectively. TOGA has drilled and completed a total of six exploratory wells on these ATPs, three of which are being tested and evaluated, and three of which were plugged and abandoned. The Company has applied for renewal on ATP 655 on the acreage held at October 31, 2003. The Company expects additional exploratory work will be conducted in 2004. TOGA has met all prior term expenditure requirements on retained acreage. TOGA also holds a 25% interest in ATP 554, which covers approximately 111,000 acres.
During the current term ending October 31, 2003, ATP 655 had remaining expenditure requirements totaling approximately $924,000. The Company met a portion of those expenditure requirements and has made application to the Queensland DNRM for the remaining expenditure requirements to be extended to October 31, 2004 in association with the
12
application for renewal discussed previously. During the current term ending February 29, 2004, ATP 675 has no remaining expenditure requirements. The Company will continue to evaluate ATP’s 655 and 675 and will either meet the expenditure requirements or relinquish additional acreage based upon evaluation of data. On ATP 554 several conditions must be met by a third party before the Company can determine its commitment.
United States
The Company holds a 50% working interest in the Lay Creek coalseam gas project located in Moffat County, Colorado. The project includes various leasehold interests covering over 82,000 gross acres. Koch Exploration Company (“Koch”), an unaffiliated third party, holds the remaining 50% working interest under the terms of an agreement to conduct exploratory drilling over this area jointly. On October 1, 2003, through joint agreement with the Company, Koch became operator of the Lay Creek project. Koch paid the Company approximately $2 million for this interest at closing in May 2001 and agreed to pay the Company approximately $2 million for the Company’s share of costs to drill and complete wells on the project acreage. The Company drilled and completed two exploratory coalseam gas wells on this acreage during 2001 and completed a four-well pilot drilling program around one of the exploratory wells in early May 2002. During the third and fourth quarters of 2002, the Company drilled four additional exploratory coalseam gas wells offsetting the second exploratory well drilled in 2001 on the project. The Company is currently evaluating the gas and water production from these two five-well pilot programs in order to determine economic viability of the production. The Company and Koch plan to begin drilling additional pilot wells in December 2003 offsetting the second five-well pilot program.
In February 2002, the Company sold a 60% interest in the Nine Mile Prospect, conventional oil and gas exploration prospect, which is also located in Moffat County, Colorado, to Elm Ridge Resources (“Elm Ridge”), an unaffiliated third party, for approximately $595,000. The project comprises approximately 49,000 gross acres. Elm Ridge also agreed to pay one-half of the Company’s share of drilling costs to an agreed casing point on the first well for its 40% retained interest. In September 2002, the Company announced the completion and initial testing of the Federal 34-1 on the prospect. Since then the Company has become the operator of the project, two dry holes were drilled and the Federal 34-1 test has not been as positive as initially projected. As a result, the Company recorded domestic ceiling test write-downs at June 30, 2003 of $2.2 million and $200,000 at September 30, 2003 under the full cost method of accounting. In exchange for Tipperary assuming Elm Ridge’s obligation for plugging and abandoning costs, Elm Ridge has assigned its interest in portions of the Nine Mile prospect to Tipperary. The Company is evaluating the Nine Mile project and is seeking industry partners before resuming exploratory work.
In November 2002, the Company sold to Kerr-McGee Rocky Mountain Corporation (“Kerr-McGee’), an unaffiliated third party, interests ranging from 75% to 80% in the Frenchman and Republican prospects in eastern Colorado for $4,800,000 in cash. The Company retained the remaining 25% to 20% interests in the acreage. Total acreage in the project is approximately 280,000 gross acres. The Company and Kerr-McGee simultaneously entered into a joint operating agreement designating Kerr-McGee as operator. In the second quarter of 2003, the Company drilled its first well on the Frenchman prospect and conducted a gas production test and is evaluating the results. During the third quarter of 2003, the Company drilled four additional wells of which two were completed and two were plugged and abandoned. The Company has conducted gas production tests on one of the completed wells and is evaluating the results.
In July 2003, the Company sold to an unaffiliated third party, a 75% interest in the Stateline prospect in western Nebraska for approximately $3 million in cash. The Company retained a 25% interest in the acreage. Total gross acreage sold in the project is approximately 97,000 acres. In October 2003, the Company sold additional acreage to the same party, bringing total sales proceeds to approximately $3.2 million and total gross acreage sold to 117,000. The purchaser will serve as operator of the project. In accordance with the full cost accounting rules, the Company is recording the proceeds as a reduction of its domestic full cost pool, with no gain being recognized.
Financial Condition, Liquidity and Capital Resources
The Company had unrestricted cash and cash equivalents of $1,066,000 as of September 30, 2003, compared to $1,725,000 as of December 31, 2002. During the third quarter of 2003, the Company received approximately $36 million in cash, drawing down $7 million from the $25 million long-term, unsecured credit facilities described in Note 2 to the Consolidated Financial Statements and borrowing $29 million from STEL also discussed in Note 2 to the Consolidated Financial Statements. The $7 million
13
described previously was primarily used to fund ongoing development of the Comet Ridge project while the $29 million was used to retire a $22 million debt with TCW and purchase a $7.7 million royalty interest TCW held in the Comet Ridge project. The Company has funded operations and capital expenditures excluding the purchase of the TCW royalty interest for the nine months ended September 30, 2003 using primarily (a) $1.7 million of cash on hand at December 31, 2002, (b) a $4.7 million short-term loan from Slough in February and March 2003 that was repaid on April 2, 2003, (c) $21.1 million in borrowings from STEL under the $25 million facility and (d) proceeds of $2.9 million from the sale of assets.
The Company anticipates funding operations and domestic and Australian non-discretionary exploratory capital expenditures for the remainder of 2003 using (a) net gas revenues; (b) funds remaining (approximately $3.9 million) under the $25 million credit facilities from Slough Trading Estates Limited (“STEL”), a UK company and wholly-owned subsidiary of Slough Estates plc and parent of Slough Estates USA Inc. (“Slough”), which owns 61.3% of the Company’s outstanding common stock (See Note 2 to the Consolidated Financial Statements); (c) approximately $400,000 of net proceeds from the sale of certain oil and gas properties; and (d) approximately $4 million in additional loans from STEL or Slough.
In order to fund discretionary capital expenditures in 2003 in excess of these cash resources and to fund capital expenditures beyond 2003, the Company will require alternative sources of capital. Potential additional sources of funding are expected to include additional debt financings and asset sales. The Company is currently in formal discussions with a group of banks interested in providing AUD $150 million in senior debt financing to TOGA. The Company is seeking the financing to be (a) substantially available in December of 2003, (b) secured by the Company’s consolidated interests in the Comet Ridge project in Queensland, Australia, and (c) partially guaranteed by Slough Estates plc, STEL’s UK parent. If obtained, the Company anticipates that the financing would be used to repay the Company’s long-term debt with STEL, including the $29 million long-term debt the Company has borrowed as described in Note 2 to the Consolidated Financial Statements, and (to the extent available) fund Comet Ridge development in 2004, 2005, and 2006.
On an ongoing basis, the Company seeks to sell its interests in its prospective acreage in the United States and retain carried working interests. In the event of such sales, the Company generates cash to reduce its investment in individual projects and fund exploration costs. However, in the event that sufficient capital cannot be generated from property sales or other funding cannot be obtained, the Company will be required to curtail planned expenditures and may have to sell additional acreage and/or relinquish acreage at prices that are not favorable to the Company.
Net cash used by operating activities was $5,668,000 during the nine months ended September 30, 2003 compared to $2,789,000 of cash used during the same period last year. The increase in cash used for operations in 2003 resulted primarily from $1.3 million in increased interest expense on debt used to fund property acquisition, exploration and development, increased operating expenses of $1.2 million necessary to fund costs associated with increased gas sales in Australia and $473,000 in increased general and administrative expense. The following table provides a detailed analysis of capital expenditures of $26.3 million during the nine months ended September 30, 2003.
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Capital Expenditures Activity
(in thousands)
Australia: | |||
Comet Ridge drilling and completion | $ | 9,100 | |
Comet Ridge facilities and equipment | 5,021 | ||
Comet Ridge royalty purchase | 7,669 | ||
Other | 401 | ||
Domestic: | |||
Leasehold acquisitions | 1,688 | ||
Nine Mile drilling and completion | 1,180 | ||
Lay Creek drilling and completion | 508 | ||
Frenchman exploratory | 138 | ||
Other | 635 | ||
Total | $ | 26,340 | |
In January 2001, Slough advanced the Company $2.5 million for the purchase of a drilling rig which the Company has leased to an unaffiliated drilling contractor in Australia. This loan bears interest at a fixed rate of 10% per annum and matures on July 31, 2004. Principal payments are due monthly equal to all rents the Company receives from the drilling contractor and for accrued interest on the balance of the loan. However, there are no mandatory principal payments prior to the maturity. During the first nine months of 2003, the Company received $440,000 in rent which was used for principal payments. As of September 30, 2003, the balance due on this loan was $1.47 million. The drilling contractor has an option to buy the drilling rig from the Company prior to June 2006 for a cash payment equal to $1.47 million as of September 30, 2003 less any subsequent payments made by the contractor after September 30, 2003 through the date the option is exercised.
15
Results of Operations—Comparison of the Three Months Ended September 30, 2003 and 2002
The Company incurred a net loss of $8,804,000 for the three months ended September 30, 2003, compared to a net loss of $1,626,000 for the three months ended September 30, 2002. The increased net loss for the three months ended September 30, 2003 is primarily due to the $5.1 million write-off of deferred financing costs described in Note 2 to the Consolidated Financial Statements. Additionally, the Company experienced in the third quarter a foreign exchange loss of $1.1 million on accounts related to its Australian operations which contributed further to the increased net loss in 2003. The table below provides a comparison of operations for the three months ended September 30, 2003 with those of the prior year’s quarter. The table is intended to provide a comparative review of significant operational items and, accordingly, nominal differences may exist from the amounts presented in the accompanying financial statements. Certain prior period amounts have been reclassified to ensure comparability.
| Three Months Ended September 30 | Increase (Decrease) | % Increase (% Decrease) | ||||||||||||
| 2003 | 2002 | |||||||||||||
Worldwide operations: | ||||||||||||||
Operating revenue | $ | 1,714,000 | $ | 1,092,000 | $ | 622,000 | 57 | % | ||||||
Gas volumes (Mcf) | 1,149,000 | 984,000 | 165,000 | 17 | % | |||||||||
Oil volumes (Bbls) | — | (2,900 | ) | 2,900 | N/A | |||||||||
Average gas price per Mcf | $ | 1.49 | $ | 1.19 | $ | 0.30 | 25 | % | ||||||
Average oil price per Bbl | $ | — | $ | 26.21 | (26.21 | ) | N/A | |||||||
Operating expenses | $ | 1,256,000 | $ | 807,000 | $ | 449,000 | 56 | % | ||||||
Average operating cost per Mcfe equivalent (“Mcfe”) sold | $ | 1.09 | $ | 0.83 | $ | 0.26 | 32 | % | ||||||
General and administrative | $ | 1,353,000 | $ | 1,106,000 | $ | 247,000 | 22 | % | ||||||
Depreciation, depletion and amortization (“DD&A”) | $ | 455,000 | $ | 289,000 | $ | 166,000 | 57 | % | ||||||
Write-off of deferred loan costs | $ | 5,069,000 | $ | — | $ | 5,069,000 | N/A | |||||||
Interest expense | $ | 1,403,000 | $ | 797,000 | $ | 606,000 | 76 | % | ||||||
Australia operations: | ||||||||||||||
Operating revenue | $ | 1,710,000 | $ | 1,227,000 | $ | 483,000 | 39 | % | ||||||
Gas volumes (Mcf) | 1,149,000 | 1,002,000 | 147,000 | 15 | % | |||||||||
Average gas price per Mcf | $ | 1.49 | $ | 1.22 | $ | 0.27 | 22 | % | ||||||
Operating expenses | $ | 978,000 | $ | 723,000 | $ | 255,000 | 35 | % | ||||||
Average operating cost per Mcf sold | $ | 0.85 | $ | 0.72 | $ | 0.13 | 18 | % | ||||||
Oil and Gas property DD&A | $ | 417,000 | $ | 270,000 | $ | 147,000 | 54 | % | ||||||
Other DD&A | $ | 25,000 | $ | 8,000 | $ | 17,000 | 213 | % | ||||||
Oil and Gas DD&A rate per Mcf sold | $ | 0.36 | $ | 0.27 | $ | 0.09 | 33 | % | ||||||
Domestic operations: | ||||||||||||||
Operating revenue | $ | 4,000 | $ | (135,000 | ) | $ | 139,000 | N/A | ||||||
Gas volumes (Mcf) | 1,000 | (18,000 | ) | 19,000 | N/A | |||||||||
Oil volumes (Bbls) | — | (2,900 | ) | 2,900 | N/A | |||||||||
Average gas price per Mcf | $ | 4.08 | $ | 3.28 | $ | 0.80 | 24 | % | ||||||
Average oil price per Bbl | $ | — | $ | 26.21 | (26.21 | ) | N/A | |||||||
Operating expenses | $ | 278,000 | $ | 84,000 | $ | 194,000 | 231 | % | ||||||
Average operating cost per Mcfe sold | $ | 278.00 | $ | — | 278.00 | N/A | ||||||||
Oil and Gas property DD&A | $ | — | $ | — | $ | — | 0 | % | ||||||
Other DD&A | $ | 13,000 | $ | 12,000 | $ | 1,000 | 8 | % | ||||||
Oil and Gas DD&A rate per Mcfe sold | — | $ | — | — | 0 | % | ||||||||
The following narrative should be read in conjunction with the above table
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Revenues and Sales Volumes
Gas volumes sold in Australia increased 15% due to increased gas sales from existing wells and an increase in gas deliveries. Gas revenues in Australia increased by 39% due to the increase in sales volumes, an increase in the average sales price received and changes in exchange rates. The Company’s gas sales contracts in Australia are long-term fixed price contracts with yearly adjustments for inflation. The 22% increase in average gas sales price in Australia is due primarily to an approximate 14% increase in the value of the Australian dollar in relation to the U.S. dollar and inflation adjustments.
In natural gas production operations, joint owners sometimes sell more or less than the production volumes to which they are entitled based on their revenue ownership interest. The joint operating agreement includes gas balancing provisions to govern production allocations in this situation. The Company records a natural gas imbalance in other liabilities if any excess takes of natural gas exceed its remaining proved reserves for the property. As of September 30, 2003, the Company had taken and sold more than its share of natural gas volumes produced from the Comet Ridge project, and was overproduced by approximately 1,820 MMcf. Based on the average price of $1.43 per Mcf received during the first nine months of 2003 from these sales, this represents $2.6 million in gas revenues. No liability has been recorded for the excess volumes taken as they do not exceed the Company’s share of remaining proved reserves. Under the terms of the gas balancing agreement, the Company may be required to reduce the monthly volumes it sells by up to 50% of its entitled share of sales, to enable underproduced parties to sell more than their entitled share of the gas sales and cure the imbalance. Any reduction in monthly volumes will negatively affect the Company’s revenues, and operating expenses will not decline proportionately.
During the third quarter of 2003, the Company had minimal domestic revenue. Domestic revenues and volumes in 2002 related to the West Buna field which the Company sold in the third quarter of 2002.
Costs and Expenses
Operating expenses in Australia increased 35% due to an increase in the number of producing wells, increased costs associated with delivering increasing gas volumes and an approximate 14% decrease in the value of the U.S. dollar in relation to the Australian dollar. Average operating cost per Mcf sold increased 18% to $0.85 for the three months ended September 30, 2003. If the field were selling gas at the field’s current production and compression capacity, management estimates operating costs per Mcf would approximate $0.40. Australian oil and gas property DD&A expense increased 54% due to higher production volumes and higher finding costs for reserve additions in the third quarter.
Domestic operating expenses in the third quarter of 2003 are largely attributable to the Lay Creek coal bed methane project where the initial ten wells are in the early dewatering phase. Without these Lay Creek operating expenses, the average domestic operating cost per Mcf sold would be reduced substantially to $2.00 per Mcf. There were no domestic DD&A expenses in 2003 and 2002 due to the aforementioned sale of the Company’s West Buna field.
General and administrative (“G&A”) expenses for the third quarter of 2003 increased 22% when compared to the three months ended September 30, 2002. For the third quarter of 2003, increased G&A costs can be attributed to assuming operations at Comet Ridge and the ongoing litigation with Tri-Star. See Note 5 to the Consolidated Financial Statements.
Other Income (Expense)
In the third quarter of 2003 the Company wrote off $5,069,000 in deferred loan costs related to the TCW loan which was retired on August 15, 2003. Interest expense increased to $1,403,000 from $797,000, due primarily to increased loan balances in the third quarter of 2003 when compared to the same period in 2002. In accordance with SFAS No. 52, “Foreign Currency Translation” (“SFAS 52”), the Company recognized a foreign currency exchange loss of $1,053,000 related to the TOGA debt to be repaid. Substantially all of the foreign exchange loss relates to intercompany debt TOGA owed the Company prior to August 15, 2003. As described in Note 2 to the Consolidated Financial Statements, the non-permanent portion of intercompany debt was substantially reduced on August 15, 2003. This reduction is expected to substantially reduce future foreign currency gains and losses.
17
Results of Operations—Comparison of the Nine Months Ended September 30, 2003 and 2002
The Company incurred a net loss of $13,145,000 for the nine months ended September 30, 2003, compared to a net loss of $4,146,000 for the nine months ended September 30, 2002. The greater net loss for the nine months ended September 30, 2003 is primarily due to the $5.1 million write-off of deferred financing costs described in Note 2 to the Consolidated Financial Statements and $1.7 million in additional interest expense due to carrying higher loan balances in 2003. Operating expense increases were caused primarily by increases in the production and sale of gas in Australia. Other significant transactions in 2003 include a total of $2.4 million in write-downs of oil and gas properties, which were substantially offset by a $2.1 million foreign currency gain in 2003 related to its Australian operations. In 2002, a gain of $766,000 on a sale of assets was recognized. The table below provides a comparison of operations for the nine months ended September 30, 2003 with those of the nine months ended September 30, 2002. The table is intended to provide a comparative review of significant operational items and, accordingly, nominal differences may exist from the amounts presented in the accompanying financial statements. Certain prior period amounts have been reclassified to ensure comparability.
Nine Months Ended September 30 | Increase | % Increase | |||||||||||
| 2003 | 2002 | (Decrease) | (% Decrease) | ||||||||||
Worldwide operations: | |||||||||||||
Operating revenue | $ | 4,764,000 | $ | 3,574,000 | $ | 1,190,000 | 33 | % | |||||
Other revenue | $ | — | $ | 122,000 | $ | (122,000 | ) | N/A | |||||
Gas volumes (Mcf) | 3,332,000 | 2,684,000 | 648,000 | 24 | % | ||||||||
Oil volumes (Bbls) | — | 11,000 | (11,000 | ) | N/A | ||||||||
Average gas price per Mcf | $ | 1.43 | $ | 1.25 | $ | 0.18 | 14 | % | |||||
Average oil price per Bbl | — | $ | 19.11 | (19.11 | ) | N/A | |||||||
Operating expenses | $ | 3,320,000 | $ | 2,130,000 | $ | 1,190,000 | 56 | % | |||||
Average operating cost per Mcf equivalent (“Mcfe”) sold | $ | 1.00 | $ | 0.77 | $ | 0.23 | 30 | % | |||||
General and administrative | $ | 4,165,000 | $ | 3,692,000 | $ | 473,000 | 13 | % | |||||
Depreciation, depletion and amortization (“DD&A”) | $ | 1,161,000 | $ | 1,124,000 | $ | 37,000 | 3 | % | |||||
Write-off of deferred loan costs | $ | 5,069,000 | $ | — | $ | 5,069,000 | N/A | ||||||
Interest expense | $ | 3,883,000 | $ | 2,191,000 | $ | 1,692,000 | 77 | % | |||||
Australia operations: | |||||||||||||
Operating revenue | $ | 4,753,000 | $ | 3,147,000 | $ | 1,606,000 | 51 | % | |||||
Other revenue | $ | — | $ | 120,000 | $ | (120,000 | ) | (100 | %) | ||||
Gas volumes (Mcf) | 3,330,000 | 2,616,000 | 714,000 | 27 | % | ||||||||
Average gas price per Mcf | $ | 1.43 | $ | 1.20 | $ | 0.23 | 19 | % | |||||
Operating expenses | $ | 2,660,000 | $ | 1,774,000 | $ | 886,000 | 50 | % | |||||
Average operating cost per Mcf sold | $ | 0.80 | $ | 0.68 | $ | 0.12 | 18 | % | |||||
Oil and Gas property DD&A | $ | 1,070,000 | $ | 807,000 | $ | 263,000 | 33 | % | |||||
Other DD&A | $ | 53,000 | $ | 118,000 | $ | (65,000 | ) | (55 | %) | ||||
Oil and Gas DD&A rate per Mcf sold | $ | 0.32 | $ | 0.31 | $ | 0.01 | 3 | % | |||||
Domestic operations: | |||||||||||||
Operating revenue | $ | 11,000 | $ | 429,000 | $ | (418,000 | ) | N/A | |||||
Gas volumes (Mcf) | 2,000 | 68,000 | (66,000 | ) | N/A | ||||||||
Oil volumes (Bbls) | — | 11,000 | (11,000 | ) | N/A | ||||||||
Average gas price per Mcf | $ | 3.99 | $ | 3.11 | $ | 0.88 | 28 | % | |||||
Average oil price per Bbl | $ | — | $ | 19.11 | (19.11 | ) | N/A | ||||||
Operating expenses | $ | 660,000 | $ | 356,000 | $ | 304,000 | 85 | % | |||||
Average operating cost per Mcfe sold | $ | 330.00 | $ | 2.49 | 327.51 | 13,153 | % | ||||||
Oil and Gas property DD&A | $ | — | $ | 163,000 | $ | (163,000 | ) | N/A | |||||
Other DD&A | $ | 38,000 | $ | 36,000 | $ | 2,000 | 6 | % | |||||
Oil and Gas DD&A rate per Mcfe sold | — | $ | 1.22 | (1.22 | ) | N/A | |||||||
The following narrative should be read in conjunction with the above table
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Revenues and Sales Volumes
Gas volumes sold in Australia increased 27% due to increased gas sales from existing wells, new wells drilled and an increase in gas deliveries. Gas revenues in Australia increased by 51% due to the increase in sales volumes, an increase in the average sales price received and changes in exchange rates. The Company’s gas sales contracts in Australia are long-term fixed price contracts with yearly adjustments for inflation. The 19% increase in average gas sales price in Australia is due primarily to an approximate 13% increase in the value of the Australian dollar in relation to the U.S. dollar and inflation adjustments.
During the first nine months of 2003, the Company had minimal domestic revenue. Domestic revenues and volumes in 2002 relate to the West Buna field which the Company sold in the second quarter of 2002.
Costs and Expenses
Operating expenses in Australia increased 50% due to an increase in the number of producing wells, increased costs associated with delivering increasing gas volumes and an approximate 13% decrease in the value of the U.S. dollar in relation to the Australian dollar. Operating expenses also increased due to the Company’s increase in ownership in the Comet Ridge project in mid-2002. Average operating cost per Mcf sold increased 18% to $0.80 for the nine months ended September 30, 2003. If the field were selling gas at the field’s current production and compression capacity, management estimates operating cost per Mcf would approximate $0.40. A 33% increase in Australian oil and gas property DD&A expense is attributed primarily to higher production volumes and an increase in the depletion rate. Higher finding costs for reserves added is the principal factor increasing the depletion rate.
Domestic operating expenses in the first nine months of 2003 are largely attributable to the Lay Creek coal bed methane project where the initial ten wells are in the early dewatering phase. Without these Lay Creek operating expenses, the average domestic operating cost per Mcf sold would be reduced substantially to $6.00 per Mcf. Operating expenses in the first nine months of 2002 include expenses from the West Buna field. Domestic DD&A expenses decreased due to the aforementioned sale of the Company’s West Buna field.
General and administrative (“G&A”) expenses for the first nine months of 2003 increased 13% when compared to the nine months ended September 30, 2002. For the first nine months of 2003, increased G&A costs are principally attributed to assuming operations at Comet Ridge.
Other Income (Expense)
In the third quarter of 2003 the Company wrote off $5,069,000 in deferred loan costs related to the TCW loan which was retired on August 15, 2003. Interest expense increased to $3,883,000 from $2,191,000 due primarily to increased loan balances in the first nine months of 2003 when compared to the same period in 2002. In accordance with SFAS No. 52, “Foreign Currency Translation” (“SFAS 52”), the Company recognized a foreign currency exchange gain of $2,060,000 related to the TOGA debt to be repaid. Substantially all of this foreign exchange gain relates to intercompany debt TOGA owed the Company prior to August 15, 2003. As described in Note 2 to the Consolidated Financial Statements, the non-permanent portion of intercompany debt was substantially reduced on August 15, 2003 . This reduction is expected to substantially reduce future foreign currency gains and losses.
Item 4.Controls and Procedures
As of the end of the period covered by this report, we evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures over financial reporting pursuant to Rule 13a-15 and 15d-15 of the Securities Exchange Act of 1934. Based upon that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures over financial reporting are adequate and effective in timely alerting them to material information required to be included in this quarterly report on Form 10-Q.
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Disclosure controls and procedures, no matter how well designed and implemented, can provide only reasonable assurance of achieving an entity’s disclosure objectives. The likelihood of achieving such objectives is affected by limitations inherent in disclosure controls and procedures. These limitations include the fact that human judgment in decision-making can be faulty and that breakdowns in internal control can occur because of human failures such as simple errors or mistakes or because of intentional circumvention of the established process.
During the period covered by this report, there have been no significant changes in our internal controls over financial reporting or in other factors, which could significantly affect internal controls over financial reporting, including any corrective actions with regard to significant deficiencies or material weaknesses.
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See Note 5 to the Consolidated Financial Statements under Part I—Item 1.
Item 6.Exhibits and Reports on Form 8-K
(a)Exhibits:
| 11. | Computation of per share earnings, filed herewith as Note 4 to the Consolidated Financial Statements. | |
| 10.98 | Fifth Amendment to Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated June 30, 2003. Confidential portions of this agreement noted by an “*” have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidentiality under Rule 24b-2 of the Securities Exchange Act of 1934. | |
| 31.1 | Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002. | |
| 31.2 | Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002. | |
| 32.1 | Certification of Chief Executive Officer of Tipperary Corporation Pursuant to 18 U.S.C. §1350. | |
| 32.2 | Certification of Chief Financial Officer of Tipperary Corporation Pursuant to 18 U.S.C. §1350. | |
The other material contracts of the Company are incorporated herein by reference from the exhibit list in the Company’s Annual Report on Form 10-KSB for the year ended December 31, 2002.
(b)Reports on Form 8-K:
The Registrant submitted a Form 8-K on August 19, 2003, under Item 12 whereby it furnished its earnings press release announcing second quarter 2003 financial results.
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Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Tipperary Corporation | ||||||||
Registrant | ||||||||
| Date: | November 14, 2003 | By: | /s/ David L. Bradshaw | |||||
David L. Bradshaw, President, Chief Executive Officer and Chairman of the Board of Directors | ||||||||
| Date: | November 14, 2003 | By: | /s/ Joseph B. Feiten | |||||
Joseph B. Feiten, Chief Financial Officer and Principal Accounting Officer | ||||||||
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| 11. | Computation of per share earnings, filed herewith as Note 4 to the Consolidated Financial Statements. | |
| 10.98 | Fifth Amendment to Gas Sales Agreement between Tipperary Oil & Gas (Australia) Pty ltd (ACN 077 536 871) as Seller and Queensland Fertilizer Assets Limited (ACN 011 062 294) as Buyer, dated June 30, 2003. Confidential portions of this agreement noted by an “*” have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidentiality under Rule 24b-2 of the Securities Exchange Act of 1934. | |
| 31.1 | Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002. | |
| 31.2 | Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002. | |
| 32.1 | Certification of Chief Executive Officer of Tipperary Corporation Pursuant to 18 U.S.C. §1350. | |
| 32.2 | Certification of Chief Financial Officer of Tipperary Corporation Pursuant to 18 U.S.C. §1350. | |
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