UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-QSB
X QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
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ACT OF 1934
For the quarterly period ended June 30, 2001
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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 small business issuer 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)
(303) 293-9379
Issuer's telephone number
Check whether the issuer (1) filed all reports required to be filed by Section
13 or 15(d) of the Exchange Act of 1934 during the past 12 months (or for such
shorter period that the registrant was required to file such reports), and (2)
has been subject to such filing requirements for the past 90 days.
Yes X No_____
---
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Class Outstanding at August 14, 2001
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Common Stock, $.02 par value 25,147,587 shares
TIPPERARY CORPORATION AND SUBSIDIARIES
Index to Form 10-QSB
Page No.
PART I. FINANCIAL INFORMATION (UNAUDITED)
Item 1. Financial Statements
Consolidated Balance Sheet
June 30, 2001 and December 31, 2000 1
Consolidated Statement of Operations
Three months and six months ended June 30, 2001 and 2000 2
Consolidated Statement of Cash Flows
Six months ended June 30, 2001 and 2000 3
Notes to Consolidated Financial Statements 4-8
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations 9-16
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 17
Item 2. Changes in Securities 17
Item 3. Defaults Upon Senior Securities 17
Item 4. Submission of Matters to a Vote of Security Holders 17
Item 5. Other Information 17
Item 6. Exhibits and Reports on Form 8-K 17
SIGNATURES 18
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
TIPPERARY CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheet
(in thousands)
(unaudited)
June 30, December 31,
2001 2000
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ASSETS
Current assets:
Cash and cash equivalents $ 2,546 $ 1,579
Restricted cash 1,635 1,459
Receivables 748 987
Prepaid drilling costs 1,720 2,219
Other current assets 257 212
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Total current assets 6,906 6,456
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Property, plant and equipment, at cost:
Oil and gas properties, full cost method 69,744 67,833
Other property and equipment 1,113 1,069
-------- --------
70,857 68,902
Less accumulated depreciation, depletion and amortization (22,826) (22,402)
-------- --------
Property, plant and equipment, net 48,031 46,500
-------- --------
Deferred loan costs 7,418 381
Other noncurrent assets 186 13
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$ 62,541 $ 53,350
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LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of note payable - related party $ - $ 317
Accounts payable 936 3,312
Accrued liabilities 596 296
Advances from joint owners 557 -
Production taxes payable 22 43
Royalties payable 244 232
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Total current liabilities 2,355 4,200
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Long-term debt 8,500 -
Long-term notes payable - related party 12,000 11,589
Advances from related party 2,500 -
Commitments and contingencies (Note 5)
Minority interest 971 42
Stockholders' equity
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; par value $.02; 50,000,000 shares
authorized; 25,157,185 issued and 25,147,587
outstanding at June 30, 2001; 24,482,185 issued and
24,472,587 outstanding at December 31, 2000 503 490
Capital in excess of par value 124,688 123,013
Accumulated deficit (88,951) (85,959)
Treasury stock, at cost; 9,598 shares (25) (25)
-------- --------
Total stockholders' equity 36,215 37,519
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$ 62,541 $ 53,350
======== ========
See accompanying notes to consolidated financial statements.
1
TIPPERARY CORPORATION AND SUBSIDIARIES
Consolidated Statement of Operations
(in thousands, except per share data)
(unaudited)
Three months ended Six months ended
June 30, June 30,
-------------------- ---------------------
2001 2000 2001 2000
------- ---------- ------- ----------
(restated) (restated)
Revenues $ 772 $ 1,811 $ 1,641 $ 4,827
Costs and expenses:
Operating 656 1,034 1,118 2,448
Depreciation, depletion and amortization 215 365 425 1,009
Gain on sale of assets - (4,973) - (4,973)
General and administrative 1,067 1,096 2,044 1,963
------- ------- ------- -------
Total costs and expenses 1,938 (2,478) 3,587 447
------- ------- ------- -------
Operating income (loss) (1,166) 4,289 (1,946) 4,380
Other income (expense):
Interest income 37 25 84 48
Interest expense (782) (348) (1,243) (806)
Foreign currency exchange gain (loss) 60 (30) (32) (75)
------- ------- ------- -------
Total other income (expense) (685) (353) (1,191) (833)
------- ------- ------- -------
Income (loss) before income taxes (1,851) 3,936 (3,137) 3,547
Income tax expense (1) 1,913 (1) 1,913
------- ------- ------- -------
Net income (loss) before minority interest (1,850) 2,023 (3,136) 1,634
Minority interest in loss of subsidiary 53 86 144 164
------- ------- ------- -------
Net income (loss) $(1,797) $ 2,109 $(2,992) $ 1,798
======= ======= ======= =======
Net income (loss) per share
Basic $ (.07) $ .09 $ (.12) $ .08
======= ======= ======= =======
Diluted $ (.07) $ .08 $ (.12) $ .08
======= ======= ======= =======
Weighted average shares outstanding
Basic 24,547 24,164 24,510 22,471
======= ======= ======= =======
Diluted 24,547 24,968 24,510 23,178
======= ======= ======= =======
2
TIPPERARY CORPORATION AND SUBSIDIARIES
Consolidated Statement of Cash Flows
(in thousands)
(unaudited)
Six months ended
June 30,
---------------------------
2001 2000
-------- --------
(restated)
Cash flows from operating activities:
Net income (loss) $(2,992) $ 1,798
Adjustments to reconcile net income (loss) to net cash
provided by (used in) operating activities:
Depreciation, depletion and amortization 425 1,009
Amortization of deferred financing costs 519 -
Gain on sale of assets - (4,973)
Deferred tax expense - 1,573
Minority interest in loss of subsidiary (144) (164)
Change in assets and liabilities:
(Increase) decrease in receivables 239 (30)
(Increase) decrease in supplies, prepayments and other
current assets 454 (355)
Increase (decrease) in accounts payable and
accrued liabilities (1,176) 416
Increase in royalties payable 12 65
Increase (decrease) in advances from joint owners 557 -
------- -------
Net cash used in operating activities (2,106) (661)
------- -------
Cash flows from investing activities:
Proceeds from asset sales 1,930 15,251
Capital expenditures (8,937) (5,055)
------- -------
Net cash provided by (used in) investing activities (7,007) 10,196
------- -------
Cash flows from financing activities:
(Increase) decrease in restricted cash (176) -
Proceeds from borrowing 15,500 -
Principal repayments (4,407) (7,889)
Proceeds from issuance of preferred and common stock - 1,821
Proceeds from issuance of warrants - 576
Payment of dividends - (79)
Payments for debt financing (837) (234)
------- -------
Net cash provided by financing activities 10,080 (5,805)
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Net increase in cash and cash equivalents 967 3,730
Cash and cash equivalents at beginning of period 1,579 5,314
Cash and cash equivalents at end of period $ 2,546 $ 9,044
======= =======
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest $ 862 $ 862
Income taxes $ - $ -
Non-cash investing and financing activities:
Issuance of stock to acquire assets $ 1,688 $ 1,861
See accompanying notes to consolidated financial statements.
3
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
- ---------------------
In the opinion of management, the accompanying unaudited financial statements
reflect all adjustments, consisting only of normal recurring adjustments, which
are necessary for a fair presentation of the consolidated financial position of
Tipperary Corporation and its subsidiaries (the "Company" or "Tipperary") at
June 30, 2001, and the results of its operations for the three-month and six-
month periods ended June 30, 2001 and 2000. 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"), and its share of assets, liabilities, revenues and expenses of
unincorporated joint ventures. All intercompany balances have been eliminated.
The accounting policies followed by the Company are included in Note 1 to the
Consolidated Financial Statements in the Annual Report on Form 10-KSB(A) for the
transition period ended December 31, 2000. These financial statements should be
read in conjunction with the Form 10-KSB(A).
Impact of New Accounting Pronouncements
- ---------------------------------------
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities" ("SFAS 133"). This statement, as amended by SFAS 137
and SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedging
Activities, an amendment of SFAS 133," is effective for all fiscal quarters of
fiscal years beginning after June 15, 2000. 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 derivatives. The Company's adoption of SFAS 133, effective January
1, 2001, did not have a significant impact upon the Company's financial position
or results of operations. Tipperary entered into a foreign exchange contract to
purchase Euros that were used to purchase a drilling rig from a manufacturer in
Italy on March 30, 2001.
Liquidity and Operations
- ------------------------
As indicated in prior reports filed with the United States Securities and
Exchange Commission ("SEC"), the Company does not have sufficient operating cash
flows to support its near term capital needs and overhead because it is
experiencing reduced cash flows as a result of the sale of most of its U.S. oil
and gas production in fiscal 2000. In order to meet its capital needs, the
Company has filed a registration statement with the SEC to raise up to $30
million pursuant to a public offering to be made exclusively to the Company's
stockholders. The Company cannot estimate the timing of the proposed rights
offering, but its majority (54.1%) stockholder, Slough Estates USA, Inc.
("Slough"), has indicated that it is willing to invest up to $20 million in the
offering, of which $12 million of net proceeds will be used to pay debt owed to
Slough. Alternatively, Slough has indicated that it is willing to provide up to
$8 million of additional debt financing on an as needed basis to the Company
through March 2002. The terms of any such financing have not been negotiated. In
the event that the proposed rights offering is not made, the Company anticipates
it will also evaluate other various financing alternatives, including additional
debt and equity financing, as well as asset sales.
NOTE 2 - RELATED PARTY TRANSACTIONS AND DEBT
At June 30, 2001, the Company had a corporate loan of $12,000,000 due Slough.
The balance of this loan at December 31, 2000 was $7,500,000. Tipperary
increased this debt by executing a new note for $12 million with the same terms
as the $7.5 million note, which included a maturity date of March 31, 2003.
Interest is due quarterly on the corporate loan at the 90-day London Interbank
Offered Rate plus 3.5% (7.33% at June 30, 2001). The Company intends to repay
this $12,000,000 loan with a portion of the proceeds from its proposed rights
offering.
In January 2001, Slough advanced the Company $2,500,000 to finance the purchase
of a drilling rig, which has been leased to an unaffiliated drilling contractor
in Australia. The advances were made under the terms of a financing agreement
which contemplated that the Company's 90% owned subsidiary, TOGA, would sell the
rig to Slough and enter into a lease agreement to lease the rig from Slough.
The parties subsequently agreed to restructure the financing as a loan and will
execute a promissory note for $2.5 million. The Company anticipates that the
terms of the
4
note will be consistent with the terms of the financing agreement and will
provide for monthly interest payments at a rate of 10% per annum, principal
payments to be made in the amount of and upon receipt of rent payments received
by TOGA and a maturity date of July 31, 2003. The Company has made payments to
Slough of accrued interest monthly at a rate of 10% per annum. Related party
debt due Slough at December 31, 2000, included the aforementioned corporate loan
of $7,500,000 and a project-financing loan with a balance of $4,406,000 bearing
interest at 10% per annum. In February 2001, the Company repaid the project-
financing loan using the initial proceeds of its financing with TCW Asset
Management Company ("TCW") discussed in Note 3.
NOTE 3 - LONG-TERM DEBT - UNRELATED PARTY
On April 28, 2000, the Company entered into a credit agreement with TCW ("Credit
Agreement") that provides a borrowing facility of up to $17 million to be funded
on or before December 31, 2001 upon the satisfaction of certain conditions. The
obligation to repay the advances and accrued interest is evidenced by senior
secured promissory notes bearing interest at the rate of 10% per annum and
payable quarterly. Tipperary must also make monthly payments to TCW equal to a
6% overriding royalty from the gas sales revenues received by TOGA from the
Comet Ridge project. Upon payment of the loan in full, TCW has the option to
sell this overriding royalty interest to Tipperary at the net present value of
the royalty's share of future net revenues from the then proved reserves,
discounted at a rate of 15% per annum. Tipperary has the right to purchase the
interest from TCW, when both the loan has been repaid in full and TCW has
achieved a 15% internal rate of return on its investment, at the net present
value of the royalty's share of future net revenues from the then proved
reserves, discounted at a rate of 15% per annum. Principal payments are due
quarterly in an amount equal to the greater of a percentage of TOGA's operating
cash flow as defined or a scheduled minimum principal payment. The scheduled
minimum principal payment begins in March 2003 and will be equal to 5% of the
unpaid principal balance, increasing to 9% in March 2004 and 10% in March 2005.
The outstanding principal balance is due in full on March 30, 2006.
In February 2001, the Company received an initial loan advance of $7.5 million
under the Credit Agreement. Proceeds from this initial advance were used to
repay the $4,406,000 Comet Ridge project-financing loan due to Slough and pay
$1.5 million in initial costs of a 20-well drilling program on the Comet Ridge
project, with the balance provided as working capital for lender-approved
purposes. In May 2001, the Company received an additional loan advance of $1.0
million from TCW to fund drilling costs related to the 20-well drilling program.
Of the $8.5 million remaining under the credit facility, about $4.8 million is
available to finance the Company's share of additional costs for the 20-well
drilling program and the remainder may be used for other lender-approved
drilling projects. Upon the receipt of this initial funding, the Company
recorded deferred financing costs of approximately $6.8 million for the present
value (discounted at 15%) of the overriding royalty conveyed to TCW. This cost
reduced the book value of oil and gas properties and is amortized as interest
expense over the life of the loan. Deferred loan costs at June 30, 2001 also
include approximately $1,000,000 of other costs incurred to obtain the TCW
financing, which are likewise being amortized to interest expense over the life
of the loan.
5
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):
Three months ended Six months ended
June 30, June 30,
--------------------- ---------------------
2001 2000 2001 2000
------- ---------- ------- ----------
(restated) (restated)
Numerator:
Net income (loss) $(1,797) $ 2,109 $(2,992) $ 1,798
Less: preferred stock dividends - - - (79)
------- -------- ------- --------
Net income (loss) available for common stockholders $(1,797) $ 2,109 $(2,992) $ 1,719
Denominator:
Weighted average shares outstanding 24,547 24,164 24,510 22,471
Effect of dilutive securities:
Assumed conversion of dilutive options - 804 - 707
------- -------- ------- --------
Weighted average shares and dilutive potential
common shares 24,547 24,968 24,510 23,178
======= ======== ======= ========
Basic earnings (loss) per share $ (.07) $ .09 $ (.12) $ .08
======= ======== ======= ========
Diluted earnings (loss) per share $ (.07) $ .08 $ (.12) $ .08
======= ======== ======= ========
Potentially dilutive common stock from the exercise
of options and warrants not included in EPS
that would have been antidilutive 864 - 1,029 -
======= ======== ======= ========
Total common stock and warrants which could
potentially dilute basic EPS in future periods 3,529 3,343 3,529 3,343
======= ======== ======= ========
See Note 8 for comparison of earnings per share as revised with earnings per
share as originally reported.
NOTE 5 - 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
- -------
involving the Comet Ridge project. By amended petition filed May 1, 2000,
Tipperary Oil & Gas Corporation joined the action as a plaintiff, along with the
already-named plaintiffs and two unaffiliated non-operating working interest
owners who previously intervened in the action as plaintiffs. James H. Butler,
Sr., and James H. Butler, Jr., owners of defendant Tri-Star Petroleum Company,
("Tri-Star") were also joined as defendants in the amended petition. The Company
and the other plaintiffs allege, among other matters, that Tri-Star and/or the
individual defendants have failed to operate the properties in a good and
workmanlike manner and have committed various other breaches of a joint
operating contract, have breached a previous mediation agreement between the
parties, have committed certain breaches of fiduciary and other duties owed to
the plaintiffs, and have committed fraud in connection with the project.
Plaintiffs also allege that Tri-Star has been removed as operator, and that
Tipperary Oil & Gas (Australia) Pty Ltd has been elected successor operator
under the operating contract. Tri-Star has answered the amended petition, and on
December 22, 2000, Tri-Star filed its first amended counterclaim alleging
tortious interference with contract, with the authority to prospect covering the
project, with contractual relationships and with vendors; commercial
disparagement; foreclosure of operator's lien and alternatively forfeiture of
undeveloped acreage; unjust enrichment and declaratory relief. As of February 8,
2001, the court enjoined Tri-Star from asserting any forfeiture claims based
upon events prior to that date. Discovery is in progress and the case presently
is set for trial in December 2001. In April 2000, the trial court denied,
pending an evidentiary hearing, Tri-Star's motion to compel arbitration of audit
disputes between the parties. Tri-Star appealed that order to the Eighth Circuit
Court of Appeals for Texas, who affirmed the trial court's ruling in February,
2001. Tri-Star has appealed the matter to the Texas Supreme Court. The Texas
Supreme Court has called for briefing on the merits, which the parties have
provided. The Company cannot predict the outcome of the proceedings in the Texas
Supreme Court, although management believes that any decision potentially
impacts only those claims
6
related to joint interest audit disputes. Discovery of the underlying lawsuit is
proceeding pending any decision by the Texas Supreme Court.
In 1997, the Company filed a complaint along with several other plaintiffs in
BTA Oil Producers, et al. v. MDU Resources Group, Inc. in Stark County Court in
- ------------------------------------------------------
the Southwest Judicial District of North Dakota. The plaintiffs include major
integrated oil companies and agricultural cooperatives, as well as independent
oil and gas producers such as the Company. The plaintiffs brought the action
against the defendants for breach of gas sales contracts and processing
agreements, 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. After
the complaint was answered, both the plaintiffs and the defendants moved for
summary judgment on certain issues. On July 3 and October 4, 2000, and on March
2, 2001, the trial court entered two orders and a judgment deciding the issues
in the case. The plaintiffs prevailed on some issues, and the defendants
prevailed on other issues. The plaintiffs filed a Notice of Appeal on May 4,
2001.
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):
United
States Australia Total
------ --------- -------
Three months ended June 30, 2001
Revenues $ 162 $ 610 $ 772
Three months ended June 30, 2000
Revenues $1,250 $ 561 $ 1,811
Six months ended June 30, 2001
Revenues $ 483 $ 1,158 $ 1,641
Property, plant and equipment, net $7,058 $40,973 $48,031
Six months ended June 30, 2000
Revenues $3,751 $ 1,076 $ 4,827
Property, plant and equipment, net $4,111 $34,975 $39,086
NOTE 7 - ISSUANCE OF COMMON SHARES FOR ACQUISITION OF ADDITIONAL INTERESTS IN
COMET RIDGE PROJECT
In June 2001, the Company acquired an additional interest in the Comet Ridge
coalbed methane project in Queensland, Australia. The total interest acquired
was 2.5% in capital-bearing interest, bringing the Company's total interest to
64.75% The total purchase price of $1,688,000 was paid to the seller with the
issuance of 675,000 shares of the Company's restricted common stock with a value
of $2.50 per share on the date the transaction closed.
7
NOTE 8 - RESTATEMENT
As disclosed in the Company's Form 10-QSB for the quarterly periods ended March
31, 2000 and June 30, 2000, the Company's oil and gas properties in its U.S.
full cost pool were held for sale in connection with the Company's redirection
of focus toward increasing reserves and production of natural gas from coalbed
methane properties. The Company had suspended the depreciation, depletion and
amortization of these properties for the quarterly periods in fiscal 2000 during
which these properties were held for sale. The Company subsequently revised its
previously reported quarterly results of operation to include depreciation,
depletion and amortization of these oil and gas properties through the date of
disposal. The above revision, which increased depreciation, depletion and
amortization and gain on disposal of assets as shown below, had no effect on the
Company's full year's results of operations for fiscal 2000, nor did the
revision have any impact on cash flows for any period. The following tables
show the effect of this restatement (in thousands except per share amounts).
Quarter Ended Quarter Ended
June 30, 2000 June 30, 2000
Restated As Previously Reported
------------------ ----------------------
Depreciation, depletion and amortization $ 365 $ 195
Total costs and expenses $ (2,478) $ 2,325
Operating income (loss) $ 4,289 $ (514)
Gain on disposal of assets $ 4,973 $ 4,093
Income (loss) before income taxes $ 3,936 $ 3,226
Net income (loss) before minority interest $ 2,023 $ 1,313
Net income $ 2,109 $ 1,399
Net income (loss) per share - basic $ .09 $ .06
Net income (loss) per share - diluted $ .08 $ .06
Six Months Ended Six Months Ended
June 30, 2000 June 30, 2000
Restated As Previously Reported
---------------- ----------------------
Depreciation, depletion and amortization $ 1,009 $ 388
Total costs and expenses $ 447 $ 4,799
Operating income (loss) $ 4,380 $ 28
Gain on disposal of assets $ 4,973 $ 4,093
Income (loss) before income taxes $ 3,547 $ 3,288
Net income (loss) before minority interest $ 1,634 $ 1,375
Net Income $ 1,798 $ 1,539
Net income (loss) per share - basic $ .08 $ .07
Net income (loss) per share - diluted $ .08 $ .06
8
Item 2. Management's Discussion and Analysis or Plan of Operation
Information herein 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, as amended, for the transition period
ended December 31, 2000, for meaningful cautionary language disclosing why
actual results may vary materially from those anticipated by management.
Overview
The Company is principally engaged in the exploration for and development and
production of natural gas. The Company is primarily focused on coalbed methane
properties, with its major producing property located in Queensland, Australia.
Tipperary also holds exploration permits in Queensland and is involved in
coalbed methane exploration in the United States through projects in the Hanna
Basin of Wyoming and in western Colorado. The Company seeks to increase its
natural gas reserves through exploration and development projects and possibly
through the acquisition of producing properties.
The Company's exploration and development efforts, and the majority of its
capital investment in recent years, have been focused on the Comet Ridge coalbed
methane project in Queensland, Australia. The Company's 90%-owned Australian
subsidiary, Tipperary Oil & Gas (Australia) Pty Ltd ("TOGA"), owns a 64.75% non-
operating undivided interest in the project, which consists of Authority to
Prospect ("ATP") 526 and five petroleum leases in the Bowen Basin. The four-year
term of ATP 526 expired on October 31, 2000. The Queensland government has been
reviewing the renewal application and has recently offered to renew the ATP but
with relinquishment of approximately 10% of the 1,088,000 acres. The acreage
relinquished does not contain any existing proved reserve drilling locations.
The ATP, as renewed, will cover approximately 980,000 acres.
There have been 43 wells drilled on the Comet Ridge project, of which seven have
been drilled in 2001 as part of a 20-well drilling program proposed by the
company. Of these seven wells three have been completed and are producing, one
has been completed and is awaiting production equipment and two wells are
awaiting completion. The seventh well is currently drilling. The three new
producing wells are adding in excess of 1,500 mcf per day to total production
volumes. One of these wells has been connected to the gathering system.
In addition to the interest in the Comet Ridge property, TOGA holds a 100%
interest in other exploration permits granted to TOGA by the Queensland
government. These permits cover a total of approximately 1.5 million acres
comprising ATPs 655, 675 and 690, which have initial terms expiring on October
31, 2003, February 29, 2004 and November 30, 2004, respectively. TOGA has
drilled four exploratory wells on two of these ATPs. One of the wells has been
plugged and abandoned and the remaining three wells are being tested and
evaluated. On June 22, 2001, the Company acquired a 25% interest in ATP 554 in
Queensland from an unaffiliated third party. The interest in this ATP was
acquired under the terms of an agreement dated May 30, 2001, whereby TOGA is to
serve as operator and drill a test well on the ATP in the near term. Several
conditions must be met before the Company can be certain of its commitment, but
it believes that it will drill this prospect. The Company would bear 33.33% of
the costs to drill and complete this test well and believes that its share of
the costs will total approximately US $700,000.
9
On May 4, 2001, the Company sold a 50% working interest in its Lay Creek
project in Moffat County, Colorado to Koch Exploration Company, an unaffiliated
third party, and entered into an agreement to jointly conduct exploratory
drilling over this area. The Company received $2 million at closing and will be
reimbursed for $2 million of its share of costs to drill and complete wells on
the project acreage. If the entire reimbursement amount has not been paid
within 18 months of the closing, Koch is obligated to pay the Company the
remainder of the $2 million in cash. Under the full cost method of accounting,
no gain or loss was recognized on the sale of this interest. The Company and
Koch are committed to drill two wells in the near future subject to rig
availability or regulatory delays, and three additional wells by June 17, 2002.
The Lay Creek project currently covers approximately 61,000 acres.
In July 2001, the Company entered into an agreement with Barrett Resources, the
operator of the Hanna Basin coalbed methane project in Wyoming, to transfer a
portion of Tipperary's interest in the project to Barrett. The agreement
provides that Barrett will pay 100% of the costs to drill and complete five
additional test wells on the project. Upon completion of these wells, Tipperary
will assign Barrett a net 29% working interest and retain a net 20% working
interest in the project.
During the quarter ended June 30, 2001, the Company commenced drilling one
development well on its West Buna property in east Texas, which is currently
being completed, and drilling operations are about to begin on a second
development well. The Company believes the drilling results on the first well
indicate that it will produce commercial quantities of gas and condensate. Both
of these West Buna development wells were included in our proved reserves as
undeveloped locations.
Financial Condition, Liquidity and Capital Resources
The Company's primary sources of liquidity during the past few years have been
from debt and equity financing and sales of producing properties. Tipperary has
used these funds to pay off outstanding bank debt and for exploration and
development operations including the acquisition of additional interests in the
Comet Ridge project. Remaining funds were invested in domestic properties, most
notably in the Hanna Basin coalbed methane project and in undeveloped oil and
gas leasehold interests in Colorado.
As indicated in prior reports filed with the SEC, the Company does not have
sufficient operating cash flows to support its near term capital needs and
overhead because it is experiencing reduced cash flows as a result of the sale
of most of its U.S. oil and gas production in fiscal 2000. In order to meet its
capital needs, the Company has filed a registration statement with the SEC to
raise up to $30 million pursuant to a public offering to be made exclusively to
the Company's stockholders. The Company cannot estimate the timing of the
proposed rights offering, but its majority (54.1%) stockholder, Slough Estates
USA, Inc. ("Slough"), has indicated that it is willing to invest up to $20
million in the offering, of which $12 million of net proceeds will be used to
pay debt owed to Slough. Alternatively, Slough has indicated that it is willing
to provide up to $8 million of additional debt financing on an as needed basis
to the Company through March 2002. The terms of any such financing have not been
negotiated. In the event that the proposed rights offering is not made, the
Company anticipates it will also evaluate other various financing alternatives,
including additional debt and equity financing, as well as asset sales. The
Company has thus far been successful in selling interests in certain domestic
exploration acreage and will continue to seek partners in new and existing
prospects.
Development drilling on the Comet Ridge project and on the West Buna property in
East Texas is expected to result in increased gas sales, which will improve cash
flow in the near term as well as longer term. Tipperary is encouraged by
developments with respect to agreements for future sales of gas from the Comet
Ridge project. The Company is currently negotiating a contract
with Queensland Fertilizer Assets Ltd ("QFAL") of Queensland, Australia, which
provides that Tipperary sell up to 260 billion cubic feet of gas to QFAL over 20
years. The gas is to be consumed by a fertilizer plant QFAL intends to construct
in southeastern Queensland. Construction of the plant is expected to take
approximately two years and would begin approximately six months after QFAL
obtains project financing for the plant and governmental approvals, both of
which cannot be assured. Tipperary may seek the assistance of ENERGEX Retail Pty
Ltd or other third parties, in underwriting the gas supply obligation. ENERGEX
is a wholly owned Queensland Government Enterprise, with which Tipperary has two
existing gas contracts. The Company recently announced that ENERGEX, which had
the right to nominate purchase volumes between 10 and 15 Mmcf per day for the
final three years of the second contract, has elected to take the maximum 15
Mmcf per day. Tipperary and certain of its co-venturers participate in the
contract, and Tipperary's share is 84%.
10
The Company had unrestricted cash and temporary investments of $2,546,000 as of
June 30, 2001, compared to $1,579,000 as of December 31, 2000. At June 30,
2001, the Company had working capital of $4,551,000 compared to working capital
of $2,256,000 as of December 31, 2000. Working capital includes restricted cash
of $1,635,000 as of June 30, 2001 and $1,459,000 as of December 31, 2000. The
restricted cash as of June 30, 2001 includes cash in collateral accounts
maintained in connection with TCW financing, the use of which is restricted to
disbursements made either to TCW or as otherwise approved by TCW. During the six
months ended June 30, 2001, cash flows were provided by debt financing and oil
and gas property sales. These proceeds were used to fund capital expenditures
and operating activities.
Net cash used by operating activities was $2,106,000 during the three months
ended June 30, 2001 compared to $661,000 of cash used during the corresponding
prior year period. The decrease in net cash from operations was attributable to
the sale of most of the Company's U.S. oil and gas properties during fiscal
2000.
During the six months ended June 30, 2001, the Company had net receipts of
$10,080,000 from financing, which included borrowings of $8,500,000 from TCW and
$7,000,000 from Slough. Capital expenditures of $8,937,000 included $2,480,000
for the purchase of a drilling rig which has been leased to a drilling
contractor in Queensland, Australia (discussed below), $1,661,000 for acreage
acquisitions in Colorado, $3,028,000 for drilling, completion and other costs on
the Comet Ridge project and $276,000 for drilling and completion costs in the
Hanna Basin project. In June 2001, the Company acquired an additional 2.5%
capital-bearing interest in the Comet Ridge project bringing the Company's total
interest to 64.75%. The total purchase price of $1,688,000 was paid to the
seller with the issuance of 675,000 shares of the Company's restricted common
stock valued at $2.50 per share.
During the six months ended June 30, 2000, the Company's $5,055,000 investment
in property plant and equipment, included the acquisition of additional
interests totaling 5.5% in the Comet Ridge project for approximately $3.3
million in cash and 1,163,328 shares of the Company's common stock. The Company
received approximately $15,300,000 from the sale of domestic properties during
this six month period. Net cash used by financing activities was $5,806,000 and
included $2,400,000 received from the sale of stock and issuance of warrants in
connection with financing arrangements with two individual investors. These
equity proceeds were used to partially fund the aforementioned acquisition of
additional interests in the Comet Ridge project. With the proceeds from the sale
of domestic properties the Company made principal payments of approximately
$7,900,000 to retire long-term debt.
At December 31, 2000, the Company owed Slough $11,906,000, consisting of a
corporate loan of $7,500,000 and a project-financing loan of $4,406,000, which
was used to finance the Company's share of an eight-well drilling program on the
Comet Ridge project during fiscal 1999 and fiscal 2000. The Company repaid the
project-financing loan in February 2001, using the initial proceeds under a loan
facility with TCW discussed below. Since December 31, 2000, the Company has
borrowed an additional $4.5 million from Slough, increasing the total amount
owed to Slough to $12 million as of June 30, 2001. The promissory note for $12
million matures March 31, 2003 and bears interest at the 90-day London Interbank
Offered Rate plus 3.5%. The interest rate was 7.33% at June 30, 2001. The
Company expects to repay this $12 million loan with a portion of the proceeds
from the rights offering discussed above.
In February 2001, the Company received an initial loan advance of $7.5 million
under a $17 million borrowing facility with TCW. Proceeds from this initial
advance were used to repay Slough for the Comet Ridge project-financing loan of
$4,406,000, pay $1.5 million in initial costs of the 20-well drilling program on
the Comet Ridge project and pay approximately $240,000 of expenses related to
the financing. The balance of $1,354,000 was deposited into a collateral account
as restricted working capital to be used for lender-approved purposes. In May
2001, the Company received an additional loan advance of $1.0 million under the
TCW borrowing facility to fund drilling costs related to the 20-well drilling
program. Of the $8.5 million remaining under the credit facility, about $4.8
million is available to finance the Company's share of additional costs for the
20-well drilling program and the remainder may be used for other lender-approved
drilling projects. Upon the receipt of this initial funding, the Company
recorded deferred financing costs of $6.8 million for the present value
(discounted at 15%) of the overriding royalty conveyed to TCW. This cost reduced
the book value of oil and gas properties and is amortized as interest expense
over the life of the loan. Deferred loan costs at June 30, 2001 also include
approximately $1,000,000 of costs incurred to obtain the TCW financing, which
are likewise being amortized to interest expense over the life of the loan.
11
Tipperary proposed the 20-well drilling program to the other owners in July 2000
and estimated the cost at approximately $10 million. The Company subsequently
received Authorities for Expenditure ("AFEs") from the operator with estimated
costs of $15 million. If the operator is unable to complete the project below
the AFE costs, Tipperary's share of the $5 million difference, or almost $3.1
million, will have to be funded from other sources, as Tipperary does not have
internal sources of capital at this time to cover increased drilling and
completion costs. The Company intends to use $3.1 million of the proceeds from
its proposed rights offering to fund any excess costs.
The obligation to repay the TCW advances and accrued interest is evidenced by
senior secured promissory notes bearing interest at the rate of 10% per annum
and payable quarterly. Tipperary must also make monthly payments to TCW equal
to a 6% overriding royalty from the gas sales revenues received by TOGA from the
Comet Ridge project. Upon payment of the loan in full, TCW has the option to
sell this overriding royalty interest to Tipperary at the net present value of
the royalty's share of future net revenues from the then proved reserves,
discounted at a rate of 15% per annum. Tipperary has the right to purchase the
interest from TCW, when both the loan has been repaid in full and TCW has
achieved a 15% internal rate of return on its investment, at the net present
value of the royalty's share of future net revenues from the then proved
reserves, discounted at a rate of 15% per annum. Principal payments on the TCW
financing will be due quarterly in an amount equal to the greater of a
percentage of TOGA's operating cash flow as defined, or a scheduled minimum
principal payment. The scheduled minimum principal payment begins March 2003
and will be equal to 5% of the unpaid principal balance, increasing to 9% in
March 2004 and 10% in March 2005. The outstanding principal balance is due in
full on March 30, 2006.
In January 2001, TOGA acquired and thereafter leased a drilling rig to an
unaffiliated drilling contractor in Queensland, Australia ("Lessee"). The terms
of the lease agreement provide that the Lessee will use the rig to drill on
TOGA's ATPs. To the extent the rig is not being used for TOGA's drilling
activities, it may, with TOGA's consent, be used by the Lessee to drill wells
for others. The lease payments are structured to be due and payable with the
drilling of each well on which the rig is used. No interest or finance charge
accrues on the lease, but the Company will benefit from reduced costs to drill
wells on TOGA's ATPs. In the case of drilling on the Comet Ridge project, the
Company's co-owners also benefit from their proportionate share of the cost
reduction. The Lessee also received a two-year option to buy the rig and related
equipment at TOGA's net cost. This drilling rig has been used on the two wells
most recently drilled in the 20-well drilling program underway on the Comet
Ridge project. The Company believes that the use of the TOGA rig will reduce
future drilling costs.
In January 2001, Slough advanced the Company $2,500,000 to finance the purchase
of the drilling rig. The advances were made under the terms of a financing
agreement which contemplated that TOGA would sell the rig to Slough and enter
into a lease agreement to lease the rig from Slough. The parties subsequently
agreed to restructure the financing as a loan and will execute a promissory note
for $2.5 million. The Company anticipates that the terms of the note will be
consistent with the terms of the financing agreement and will provide for
monthly interest payments at a rate of 10% per annum, principal payments to be
made in the amount of and upon receipt of rent payments received by TOGA and a
maturity date of July 31, 2003. The Company has made monthly payments to Slough
of accrued interest at a rate of 10% per annum.
12
Results of Operations - Comparison of the Three Months Ended June 30, 2001 and
2000
As described in Note 8 to the Consolidated Financial Statements, the Company's
oil and gas properties in its U.S. full cost pool were held for sale. The
Company subsequently revised its previously reported quarterly results of
operation to include depreciation, depletion and amortization of these oil and
gas properties in its U.S. full cost pool through their date of disposal.
The Company incurred a net loss of $1,797,000 for the three months ended June
30, 2001, compared to net income of $2,109,000 for the three months ended June
30, 2000. This decrease is attributable to reduced revenues due to the sale of
most of the Company's producing properties in the U.S. during 2000. The three
months ended June 30, 2000 also include a gain of $4,973,000 associated with the
sale of these properties, which significantly increased income tax expense for
this period. The table below provides a comparison of operations for the three
months ended June 30, 2001 with those of the prior year's quarter.
Three Months Ended
June 30 June 30 Increase % Increase
2001 2000 (Decrease) (% Decrease)
----------- ----------- ------------ --------------
(restated)
Worldwide operations:
Operating Revenue $ 772,000 $1,811,000 $(1,039,000) (57%)
Oil Volumes (Bbls) 2,300 29,000 (26,700) (92%)
Gas Volumes (Mcf) 578,000 594,000 (16,000) (3%)
Average Oil Price per Bbl $ 26.89 $ 26.00 $ .89 3%
Average Gas Price per Mcf $ 1.23 $ 1.73 $ (0.50) (29%)
Operating Expense $ 656,000 $1,034,000 $ (378,000) (37%)
Average Lifting Cost per Mcf Equivalent ("Mcfe") $ 1.12 $ 1.32 $ (0.20) (15%)
General and Administrative $1,067,000 $1,096,000 $ (29,000) (3%)
Depreciation, Depletion and Amortization ("DD&A") $ 215,000 $ 365,000 $ (150,000) (41%)
DD&A Rate per Mcfe $ 0.36 $ 0.47 $ (0.11) (23%)
Interest Expense $ 782,000 $ 348,000 $ 434,000 125%
Income tax expense $ (1) $1,913,000 $(1,914,000) (100%)
Domestic operations:
Operating Revenue $ 162,000 $1,250,000 $(1,088,000) (87%)
Oil Volumes (Bbls) 2,300 29,000 (26,700) (92%)
Gas Volumes (Mcf) 22,000 138,000 (116,000) (84%)
Average Oil Price per Bbl $ 26.89 $ 26.00 $ .89 3%
Average Gas Price per Mcf $ 4.61 $ 3.39 $ 1.22 36%
Operating Expense $ 154,000 $ 739,000 $ (585,000) (79%)
Average Lifting Cost per Mcfe $ 4.57 $ 2.29 $ 2.28 100%
DD&A $ 47,000 $ 182,000 $ (135,000) (74%)
DD&A rate per Mcfe $ 1.33 $ .58 $ 0.75 129%
13
Three Months Ended
June 30 June 30 Increase % Increase
2001 2000 (Decrease) (% Decrease)
--------- ---------- ------------ ------------
(restated)
Australia operations:
Operating Revenue $610,000 $ 561,000 $ 49,000 9%
Gas Volumes (Mcf) 556,000 456,000 100,000 22%
Average Gas Price per Mcf $ 1.10 $ 1.23 $ (0.13) (11%)
Operating Expense $502,000 $ 295,000 $ 207,000 70%
Average Lifting Cost per Mcf $ 0.90 $ 0.65 $ 0.25 39%
DD&A $168,000 $ 183,000 $ (15,000) (8%)
DD&A rate per Mcf $ 0.30 $ 0.40 $ (.10) (25%)
The sale of domestic producing properties significantly reduced worldwide oil
and gas volumes. This volume reduction caused significant decreases in
worldwide operating revenue, operating expense and net income. The Company's
overall average gas price decreased due to an unfavorable exchange rate
adversely affecting the price received for Australia sales.
During the three months ended June 30, 2001, the decrease in U.S. gas production
of 116,000 Mcf was offset in part by an increase of 100,000 Mcf sold in
Australia.
The 41% decrease in worldwide DD&A costs is attributable to the sale of domestic
producing properties. Increased production and reserve volumes in Australia also
contributed to worldwide DD&A and rate reductions and reduced the Australian
DD&A rate per Mcf by 25%. While DD&A costs for domestic operations decreased,
the domestic DD&A rate per Mcfe increased as sales volumes decreased
proportionately more than did DD&A expense.
During the second quarter of 2001 Tipperary successfully completed two workovers
on the Comet Ridge project. The workover cost of $136,000 was the primary
reason for significant increases in operating expense and average lifting cost
per Mcf in our Australia operations.
The increase in the domestic lifting cost per Mcfe is attributable to lease
operating expense on the Hanna Basin project in Wyoming with no associated sales
of production.
Interest expense for the three months ended June 30, 2001 increased by $390,000
due to the amortization of deferred financing cost related to the TCW loan and
decreased by $75,000 for interest capitalization. The remaining $119,000
increase was attributable to a higher average debt balance during the current
quarter as compared to the prior year's quarter. Both deferred financing cost
amortization and interest capitalization are non-cash items and were not
included in interest expense for the three months ended June 30, 2000.
14
Results of Operations - Comparison of the Six Months Ended June 30, 2001 and
2000
As described in Note 8 to the Consolidated Financial Statements, the Company's
oil and gas properties in its U.S. full cost pool were held for sale. The
Company subsequently revised its previously reported quarterly results of
operation to include depreciation, depletion and amortization of these oil and
gas properties in its U.S. full cost pool through their date of disposal.
The Company incurred a net loss of $2,992,000 for the six months ended June 30,
2001, compared to net income of $1,798,000 for the six months ended June 30,
2000. This decrease is attributable to reduced revenues due to the sale of most
of the Company's producing properties in the U.S. during 2000. The six months
ended June 30, 2000 also included a gain of $4,973,000 associated with the sale
of these properties, which significantly increased income tax expense for this
period. The table below provides a comparison of operations for the six months
ended June 30, 2001 with those of the prior year's quarter.
Six Months Ended
June 30 June 30 Increase % Increase
2001 2000 (Decrease) (% Decrease)
---------- ---------- ------------ ------------
(restated)
Worldwide operations:
Operating Revenue $1,641,000 $4,827,000 $(3,186,000) (66%)
Oil Volumes (Bbls) 7,100 101,000 (93,900) (93%)
Gas Volumes (Mcf) 1,091,000 1,244,000 (153,000) (12%)
Average Oil Price per Bbl $ 27.88 $ 25.03 $ 2.85 11%
Average Gas Price per Mcf $ 1.32 $ 1.81 $ (0.49) (27%)
Operating Expense $1,118,000 $2,448,000 $(1,330,000) (54%)
Average Lifting Cost per Mcf Equivalent ("Mcfe") $ 1.00 $ 1.32 $ (0.32) (24%)
General and Administrative $2,044,000 $1,963,000 $ 81,000 4%
Depreciation, Depletion and Amortization ("DD&A") $ 425,000 $1,009,000 $ (584,000) (58%)
DD&A Rate per Mcfe $ 0.37 $ 0.55 $ (0.18) (33%)
Interest Expense $1,243,000 $ 806,000 $ 437,000 54%
Income tax expense $ (1) $1,913,000 $(1,914,000) (100%)
Domestic operations:
Operating Revenue $ 483,000 $3,751,000 $(3,268,000) (87%)
Oil Volumes (Bbls) 7,100 101,000 (93,900) (93%)
Gas Volumes (Mcf) 45,000 397,000 (352,000) (89%)
Average Oil Price per Bbl $ 27.88 $ 25.03 $ 2.85 11%
Average Gas Price per Mcf $ 6.36 $ 2.97 $ 3.39 114%
Operating Expense $ 302,000 $1,773,000 $(1,471,000) (83%)
Average Lifting Cost per Mcfe $ 3.62 $ 1.73 $ 1.89 109%
DD&A $ 102,000 $ 646,000 $ (544,000) (84%)
DD&A rate per Mcfe $ 1.17 $ 0.64 $ 0.53 83%
Australia operations:
Operating Revenue $1,158,000 $1,076,000 $ 82,000 8%
Gas Volumes (Mcf) 1,046,000 847,000 199,000 24%
Average Gas Price per Mcf $ 1.11 $ 1.27 $ (0.16) (13%)
Operating Expense $ 816,000 $ 675,000 $ (141,000) (21%)
Average Lifting Cost per Mcf $ 0.78 $ 0.80 $ (0.02) (3%)
DD&A $ 323,000 $ 363,000 $ (40,000) (11%)
DD&A rate per Mcf $ 0.31 $ 0.43 $ (.12) (28%)
15
The sale of domestic producing properties significantly reduced worldwide oil
and gas volumes. This volume reduction caused significant decreases in
worldwide operating revenue, operating expense and net income. The Company's
overall average gas price decreased due to an unfavorable exchange rate
adversely affecting the price received for Australia sales.
The 58% decrease in worldwide DD&A costs is attributable to the sale of domestic
producing properties. Increased production and reserve volumes in Australia also
contributed to worldwide DD&A and rate reductions and reduced the Australian
DD&A rate per Mcf by 28%. While DD&A costs for domestic operations decreased,
the domestic DD&A rate per Mcfe increased as sales volumes decreased
proportionately more than did DD&A expense.
The increase in the domestic lifting cost per Mcfe is attributable to lease
operating expense on the Hanna Basin project in Wyoming with no associated
sales of production.
Interest expense for the six months ended June 30, 2001 increased by $519,000
due to the amortization of deferred financing cost and decreased by $139,000 for
interest capitalization. The remaining $57,000 increase was attributable to a
higher average debt balance during the current quarter as compared to the prior
year's quarter. Both deferred financing cost amortization and interest
capitalization are non-cash items and were not included in interest expense for
the six months ended June 30, 2000.
16
PART II - OTHER INFORMATION
---------------------------
Item 1. Legal Proceedings
- -------
See Note 5 to the Consolidated Financial Statements under Part I -
Item 1.
Item 2. Changes in Securities and Use of Proceeds
- -------
In June 2001, the Company acquired an additional interest in the Comet
Ridge coalbed methane project in Queensland, Australia. The total
interest acquired was 2.5% in capital-bearing interest, bringing the
Company's total interest to 64.75%. The total purchase price of
$1,688,000 was paid to the seller with the issuance of 675,000 shares
of the Company's restricted common stock, which had a value of $2.50
per share on the date the transaction closed.
The offer and sale of the shares were not registered under the
Securities Act of 1933 ("Securities Act"), but rather were made
privately by the Company pursuant to the exemption from registration
provided by Section 4(2) of the Securities Act. The purchaser of the
common stock had full information concerning the business and affairs
of the Company and acquired the shares for investment purposes. The
certificates representing the securities issued bear a restrictive
legend and stop transfer instructions have been entered prohibiting
transfer of the securities except in compliance with applicable
securities laws.
Item 3. Defaults Upon Senior Securities
- -------
None
Item 4. Submission of Matters to a Vote of Security Holders
- -------
None
Item 5. Other Information
- -------
None
Item 6. Exhibits and Reports on Form 8-K
- -------
(a) Exhibits:
--------
Filed in Part I
11. Computation of per share earnings, filed herewith as
Note 4 to the Consolidated Financial Statements.
Filed in Part II
10.80 Purchase and Sale Agreement dated May 4, 2001, by and
between Tipperary Oil & Gas Corporation and Koch
Exploration Company, filed as Exhibit 10.80 on Form S-
3, SEC File No. 333-59052, filed with the Commission on
July 26, 2001, and incorporated herein by reference.
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, as amended, for the Transition Period Ended
December 31, 2000.
(b) Reports on Form 8-K:
--------------------
None
17
SIGNATURES
----------
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Tipperary Corporation
-------------------------------------------------
Registrant
Date: August 14, 2001 By: /s/ David L. Bradshaw
-------------------------------------------
David L. Bradshaw, President, Chief
Executive Officer and Chairman of the Board
of Directors
Date: August 14, 2001 By: /s/ Lisa S. Wilson
-------------------------------------------
Lisa S. Wilson, Chief Financial Officer and
Principal Accounting Officer
18