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 ACT
OF 1934
For the quarterly period ended September 30, 2001
----------------------------
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 November 7, 2001
- ---------------------------- -------------------------------
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
September 30, 2001 and December 31, 2000 1
Consolidated Statement of Operations
Three months and nine months ended September 30, 2001 and 2000 2
Consolidated Statement of Cash Flows
Nine months ended September 30, 2001 and 2000 3
Notes to Consolidated Financial Statements 4-7
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations 8-14
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 15
Item 2. Changes in Securities 15
Item 3. Defaults Upon Senior Securities 15
Item 4. Submission of Matters to a Vote of Security Holders 15
Item 5. Other Information 15
Item 6. Exhibits and Reports on Form 8-K 15-16
SIGNATURES 17
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
TIPPERARY CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheet
(in thousands)
(unaudited)
September 30, December 31,
2001 2000
------------- ------------
ASSETS
Current assets:
Cash and cash equivalents $ 2,136 $ 1,579
Restricted cash 1,670 1,459
Receivables 943 987
Prepaid drilling costs 1,906 2,219
Other current assets 327 212
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Total current assets 6,982 6,456
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Property, plant and equipment, at cost:
Oil and gas properties, full cost method 69,244 67,833
Other property and equipment 3,745 1,069
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72,989 68,902
Less accumulated depreciation, depletion and amortization (23,111) (22,402)
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Property, plant and equipment, net 49,878 46,500
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Long term receivable 1,496 -
Deferred loan costs 7,028 381
Other noncurrent assets 279 13
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$ 65,663 $ 53,350
============= ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of note payable - related party $ 155 $ 317
Accounts payable 1,614 3,312
Accrued liabilities 835 339
Royalties payable 187 232
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Total current liabilities 2,791 4,200
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Long-term debt 10,000 -
Long-term notes payable - related party 15,000 11,589
Advances from related party 2,345 -
Commitments and contingencies (Note 5)
Minority interest 903 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 $.02; 50,000,000 shares
authorized; 25,157,185 issued and 25,147,587
outstanding at September 30, 2001; 24,482,185 issued and
24,472,587 outstanding at December 31, 2000 503 490
Capital in excess of par value 124,687 123,013
Accumulated deficit (90,541) (85,959)
Treasury stock, at cost; 9,598 shares (25) (25)
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Total stockholders' equity 34,624 37,519
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$ 65,663 $ 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 Nine months ended
September 30, September 30,
----------------------- ----------------------
2001 2000 2001 2000
------- -------- ------------ -------
Revenues $ 881 $ 878 $ 2,522 $ 5,705
Costs and expenses:
Operating 500 456 1,618 2,904
Depreciation, depletion and amortization 242 220 667 1,229
(Gain) loss on sale of assets - 136 - (4,837)
General and administrative 1,029 1,100 3,073 3,063
Impairment of prepaid drilling costs - 557 - 557
------- -------- ------------ -------
Total costs and expenses 1,771 2,469 5,358 2,916
------- -------- ------------ -------
Operating income (loss) (890) (1,591) (2,836) 2,789
Other income (expense):
Interest income 33 55 117 104
Interest expense (810) (312) (2,053) (1,118)
Foreign currency exchange gain (loss) 8 (90) (24) (166)
------- -------- ------------ -------
Total other expense (769) (347) (1,960) (1,180)
------- -------- ------------ -------
Income (loss) before income taxes (1,659) (1,938) (4,796) 1,609
Income tax expense (benefit) - (340) (1) 1,573
------- -------- ------------ -------
Net income (loss) before minority interest (1,659) (1,598) (4,795) 36
Minority interest in loss of subsidiary 69 149 213 313
------- -------- ------------ -------
Net income (loss) $(1,590) $ (1,449) $ (4,582) $ 349
======= ======== ============ =======
Net income (loss) per share
Basic $ (.06) $ (.06) $ (.19) $ .02
======= ======== ============ =======
Diluted $ (.06) $ (.06) $ (.19) $ .01
======= ======== ============ =======
Weighted average shares outstanding
Basic 25,148 24,401 24,725 23,119
======= ======== ============ =======
Diluted 25,148 24,401 24,725 24,075
======= ======== ============ =======
See accompanying notes to consolidated financial statements.
2
TIPPERARY CORPORATION AND SUBSIDIARIES
Consolidated Statement of Cash Flows
(in thousands)
(unaudited)
Nine months ended
September 30,
------------------------------
2001 2000
------------- -----------
Cash flows from operating activities:
Net income (loss) $ (4,582) $ 349
Adjustments to reconcile net income (loss) to net cash
used in operating activities:
Depreciation, depletion and amortization 667 1,229
Amortization of deferred loan cost 910 -
Gain on sale of assets - (4,837)
Deferred tax expense - 1,573
Minority interest in loss of subsidiary (213) (313)
Change in assets and liabilities:
Decrease in receivables 176 74
(Increase) decrease in other current assets 198 (1,222)
Increase (decrease) in accounts payable and
accrued liabilities (987) 1,049
Increase in royalties payable (45) (21)
------------- -----------
Net cash used in operating activities (3,877) (2,119)
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Cash flows from investing activities:
Proceeds from asset sales 2,340 16,565
Capital expenditures (12,308) (7,929)
Additional investing activities (29) 15
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Net cash provided by (used in) investing activities (9,997) 8,651
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Cash flows from financing activities:
Proceeds from borrowing 20,000 -
Principal repayments (4,407) (7,978)
Increase in restricted cash (211) -
Proceeds from issuance of stock - 1,839
Proceeds from issuance of warrants - 576
Payment of dividends - (79)
Payments for other financing activities (952) (307)
------------- -----------
Net cash provided by (used in) financing activities 14,430 (5,949)
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Net increase in cash and cash equivalents 557 583
Cash and cash equivalents at beginning of period 1,579 5,314
------------- -----------
Cash and cash equivalents at end of period $ 2,136 $ 5,897
============= ===========
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest $ 1,123 $ 1,173
Income taxes $ - $ -
Non-cash investing and financing activities:
Issuance of stock to acquire assets $ (1,688) $ (2,911)
Issuance of subsidiary stock to shareholder in
exchange for contractual payment rights $ (1,074) $ -
Deferred financing costs $ 6,843 $ -
Asset sales receivable $ 1,496 $ -
Net asset acquisition payable $ 303 $ -
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") at September 30,
2001, and the results of its operations for the three-month and nine-month
periods ended September 30, 2001 and 2000. The consolidated financial
statements include the accounts of the Company 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.
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 is conducting a rights offering to its stockholders in order to raise up
to $30 million. The rights offering is being made pursuant to a registration
statement declared effective by the SEC on October 24, 2001 (SEC File No. 333-
59052). The Company's stockholders have been granted rights under this offering
to purchase one share of common stock for every 1.551 shares of stock held on
October 24, 2001, at a price of $1.85 per share. The Company's majority (52.6%)
stockholder, Slough Estates USA, Inc. ("Slough"), has indicated that it is
willing to invest up to $20 million in the rights offering, of which $15 million
of net proceeds will be used to pay debt owed to Slough. The rights offering has
an expiration date of November 30, 2001. In the event that the rights offering
does not generate sufficient capital, the Company anticipates it will also
evaluate various financing alternatives, including additional debt and equity
financing, as well as asset sales.
NOTE 2 - RELATED PARTY TRANSACTIONS AND DEBT
At September 30, 2001, the Company had a corporate loan of $15,000,000 due
Slough. The balance of this loan at December 31, 2000 was $7,500,000. The
Company issued Slough a note for $15 million in August 2001 that has the same
terms as the $7.5 million note. The note has a maturity date of March 31, 2003,
and interest is due quarterly at the 90-day London Interbank Offered Rate plus
3.5% (6.09% at September 30, 2001). The Company intends to repay this
$15,000,000 loan with a portion of the proceeds from its rights offering
discussed above.
Slough has also advanced TOGA $2.5 million for the purchase of a drilling rig
which TOGA has leased to an unaffiliated drilling contractor in Australia. This
loan bears interest at a fixed rate of 10% per annum. Payments are due monthly
for all rents TOGA receives from the drilling contractor and for accrued
interest on the balance of the loan. The Company recorded a current liability as
of September 30, 2001 for $155,000 of the loan balance based on current rents
receivable from the drilling contractor.
Related party debt due Slough at December 31, 2000, included the aforementioned
corporate loan of $7,500,000 as well as a project-financing loan with a balance
of $4,407,000 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. Further, in early
2001, the Company issued Slough shares of TOGA's stock valued at $1,074,000 in
exchange for Slough's contractual payment right to a portion of the Company's
revenues from the Comet Ridge project in Queensland, Australia.
4
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. The Company 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 the Company at the net present value of
the royalty interest's share of future net revenues from the then proved
reserves, discounted at a rate of 15% per annum. The Company also has the right
to purchase the royalty interest from TCW, when the loan has been repaid in full
and TCW has received a 15% internal rate of return on its investment, for 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 parties to the Credit Agreement executed an amended and
restated agreement and the Company received an initial loan advance of $7.5
million. Proceeds from this initial advance were used to repay the $4,407,000
project-financing loan relating to the Comet Ridge project in Queensland,
Australia, due to Slough and pay $1.5 million in initial costs of an additional
20-well drilling program on the Comet Ridge project, with the balance provided
as working capital for lender-approved purposes. Upon the receipt of this
initial funding, the Company recorded deferred financing costs of approximately
$6.8 million, which is 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 September 30, 2001 also include approximately $966,000 of
other costs incurred to obtain the TCW financing, which are likewise being
amortized to interest expense over the life of the loan.
The Company received additional loan advances under the Credit Agreement of
$1.0 million in May 2001 and $1.5 million in September 2001, bringing the total
loan balance to $10 million as of September 30, 2001. In October 2001, the
Company borrowed an additional $1.0 million under the Credit Agreement. Of the
total of $11 million currently due TCW, the Company has used $5 million to fund
advances to the operator of the Comet Ridge project for the 20-well drilling
program. The operator has drilled eight wells under the program and is
constructing a connecting pipeline that will transport gas that is currently
being flared as well as gas produced from the remaining wells to be drilled in
the 20-well drilling program. Of the $7.0 million remaining under the credit
facility at September 30, 2001, about $2.6 million may be 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 expenditures. The
Company expects to obtain the remaining $2.6 million advance for costs related
to the 20-well drilling program prior to December 31, 2001, which is the
expiration date for obtaining advances under the Credit Agreement.
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 Nine months ended
September 30, September 30,
--------------------- ---------------------
2001 2000 2001 2000
------- ------- ------- -------
Numerator:
Net income (loss) $(1,590) $(1,449) $(4,582) $ 349
Less: preferred stock dividends - - - -
------- ------- ------- -------
Net income (loss) available for common stockholders $(1,590) $(1,449) $(4,582) $ 349
======= ======= ======= =======
Denominator:
Weighted average shares outstanding 25,148 24,401 24,725 23,119
Effect of dilutive securities:
Assumed conversion of dilutive options - - - 868
------- ------- ------- -------
Weighted average shares and dilutive potential
common shares 25,148 24,401 24,725 23,987
======= ======= ======= =======
Basic earnings (loss) per share $ (.06) $ (.06) $ (.19) $ .02
======= ======= ======= =======
Diluted earnings (loss) per share $ (.06) $ (.06) $ (.19) $ .01
======= ======= ======= =======
Potentially dilutive common stock from the exercise
of options and warrants not included in EPS
that would have been antidilutive 236 1,198 712 -
======= ======= ======= =======
Total common stock and warrants which could
potentially dilute basic EPS in future periods 3,517 3,426 3,517 3,426
======= ======= ======= =======
NOTE 5 - COMMITMENTS AND CONTINGENCIES
The Company is a 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. 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. The remedies sought by the
Company include a declaratory judgment that Tri-Star has been removed as
operator under the operating agreement, that TOGA is the duly elected successor
operator, an accounting of all monies paid to and expended by Tri-Star under the
operating agreement and imposition of a constructive trust upon proceeds from
operations. The Company also seeks money damages for breaches of the operating
agreement, for breaches of a May 2, 1996 mediation agreement between the
parties, and for fraud, breach of fiduciary duties, negligence, gross negligence
and willful misconduct. The Company has not yet quantified its claim for
compensatory or exemplary damages. Tri-Star has answered the amended petition,
and is seeking money damages for alleged breaches of the operating agreement,
alleged breaches of the May 2, 1996 mediation agreement between the parties,
alleged tortious interference, commercial disparagement and unjust enrichment.
In addition, Tri-Star has pleaded for foreclosure of an operator's lien and
alternatively for forfeiture of undeveloped acreage. On February 8, 2001, the
court enjoined Tri-Star from asserting acreage forfeiture claims based upon
facts up to that date. The Company believes that Tri-Star's allegations are
groundless. The Texas Supreme Court denied Tri-Star's Petition for writ of
Mandamus (filed in connection with its motion to compel arbitration of audit
disputes for years subsequent to 1995), but no date is presently set for an
evidentiary hearing to determine the enforceability of the alleged arbitration
provision in the May 2, 1996 Mediation Agreement. An evidentiary hearing on the
Company's Application for a Temporary Injunction restraining Tri-Star from
continuing to serve as operator and requiring it to take all steps necessary for
TOGA to assume
6
operations is presently scheduled to begin on December 11, 2001. The case is set
for trial in April 2002. As Tri-Star has not yet specified money damages to be
sought at trial, it is not possible to predict a potential material effect of
the litigation on the Company.
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 September 30, 2001
Revenues $ 133 $ 748 $ 881
Three months ended September 30, 2000
Revenues $ 343 $ 535 $ 878
Nine months ended September 30, 2001
Revenues $ 616 $ 1,906 $ 2,522
Property, plant and equipment, net $6,681 $ 43,197 $49,878
Nine months ended September 30, 2000
Revenues $4,094 $ 1,611 $ 5,705
Property, plant and equipment, net $4,434 $ 37,771 $42,205
NOTE 7 - ISSUANCE OF COMMON SHARES FOR ACQUISITION OF ADDITIONAL INTERESTS IN
COMET RIDGE PROJECT
During the nine months ended September 2001, the Company increased its interest
in the Comet Ridge project from 62.25% to 65%. In June 2001, the Company
acquired a 2.5% capital-bearing interest for $1,688,000. The purchase price 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. The Company acquired an additional .25% interest in the
Comet Ridge project for approximately $169,000 in cash during August 2001,
bringing the Company's total capital-bearing interest to 65%.
7
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(A) 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.
The Company 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 90%-owned Australian subsidiary owns a 65% non-operating,
undivided interest in the Company's primary producing property located in
Queensland, Australia (the "Comet Ridge project"). The project covers
approximately 964,000 acres in the Bowen Basin and consists of Authority to
Prospect ("ATP") 526 covering approximately 686,000 acres and five petroleum
leases that cover approximately 278,000 acres. The Queensland government
recently renewed the ATP for a term of four years ending October 31, 2004. The
renewal was granted with expenditure requirements over the four-year term of
approximately US$8 million or approximately US$5.1 million net to the Company's
interest.
As of October 31, 2001, the Company has drilled 44 wells on the Comet Ridge
project of which 17 are connected to a gas pipeline, 17 are either being
dewatered or are shut in pending connection and 10 wells are in various stages
of completion. Production from the wells currently totals about 18 million
cubic feet ("MMcf") of gas per day, of which approximately 11 MMcf per day of
gas is being sold. The gas not being sold is either being flared at the
wellhead (5.4 MMcf per day) or used in gas compression (1.6 MMcf per day). The
gas production being flared is from wells that are not yet connected to the
gathering system. An additional pipeline to the compressor station is currently
being completed. This pipeline and additional gathering lines will bring most
of this gas into the sales system in the near term. The Company's share of the
current sales is approximately 7 MMcf per day. When these additional producing
wells are connected, the gathering system Company's share of total sales should
be approximately 10 MMcf per day.
The Company recently entered into a gas sales agreement to supply, upon the
satisfaction of certain conditions, up to 260 Bcf of gas to Queensland
Fertilizer Assets Limited ("QFAL"). The 20-year term of this agreement starts
in 2004 and would be in addition to the Company's current sales under the two
existing five-year contracts with ENERGEX, which together extend through May
2005. The QFAL agreement is discussed below under Financial Condition,
Liquidity and Capital Resources.
To date, the operator has drilled eight of the wells included in the Company's
20-well drilling program. Production from one of the wells is being sold and
volumes from five of the wells are being flared pending connection to the
gathering system. The remaining two wells are awaiting production equipment.
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 a total of four exploratory wells on two of these ATPs. Three wells are
being tested and evaluated and one well has been plugged and abandoned. On June
22, 2001, the Company acquired a 25% interest from an unaffiliated third party
in ATP 554 in Queensland (approximately 110,000 acres). This interest was
acquired under an agreement whereby TOGA is to
8
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 currently believes that it will drill this prospect. The Company would bear
33.33% of the costs to drill and complete this test well and estimates its net
cost will be approximately US$700,000.
On May 4, 2001, the Company sold a 50% working interest in its Lay Creek project
in Moffat County, Colorado to Koch Exploration Company ("Koch"), an unaffiliated
third party, and entered into an agreement to jointly conduct exploratory
drilling over this area. The Company received approximately $2 million at
closing and will be reimbursed for approximately $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 (or
October, 2002), Koch is obligated to pay the Company the remainder of the $2
million in cash. The Lay Creek project currently covers various leasehold
interests over an area of approximately 74,000 acres. Two exploratory
coalbed methane wells have been drilled and completed on this acreage and
production testing has recently begun. The Company and Koch are committed to
drill three additional wells by June 17, 2002.
Under the full cost method of accounting, no gain or loss was recognized on the
sale of the 50% working interest in the Lay Creek acreage. The Company has
established a long-term receivable account to record approximately $2 million to
be received from Koch for reimbursement of Lay Creek drilling costs discussed
previously. The long-term receivable was reduced during the third quarter by
approximately $480,000 for costs to drill the two wells leaving a balance as of
September 30, 2001, of $1,496,000 due the Company on or before October 4, 2002.
In July 2001, the Company entered into an agreement with Williams Production RMT
Company (fka Barrett Resources), the operator of the Hanna Basin coalbed methane
project in Wyoming, to transfer a portion of the Company's interest in the
project to Williams. The agreement provides that Williams will pay 100% of the
costs to drill and complete five additional test wells on the project. Upon
completion of these wells, the Company will assign Williams a net 29% working
interest and retain a net 20% working interest in the project. Two of the five
test wells have been drilled and the Company expects the remaining three test
wells to be drilled mid-2002. While the assignment of the 29% working interest
is pending completion of the five test wells, the Company's share of lease
operating expenses has already been reduced to 20%.
On the Company's West Buna property in east Texas, two development wells have
been drilled since June 2001. Both wells are producing gas and the Company
expects them to add approximately 300 Mcf of daily production net to the
Company's interest. The Company is currently participating in a workover of
another well in the West Buna field in an attempt to improve production rates.
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. The Company
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 elected to sell most of its U.S. oil and gas production in
fiscal 2000. This decision was made in order to reduce debt and focus on coalbed
methane exploration. In order to meet its capital needs, the Company is
conducting a rights offering to its stockholders designed to raise up to $30
million. The rights offering is being made pursuant to a registration statement
declared effective by the SEC on October 24, 2001 (SEC File No. 333-59052). The
Company's stockholders have been granted rights under this offering to purchase
one share of common stock for every 1.551 shares of stock held on October 24,
2001, at a price of $1.85 per share. The Company's majority (52.6%) stockholder,
Slough Estates USA, Inc. ("Slough"), has indicated that it is willing to invest
up to $20 million in the rights offering, of which $15 million of net proceeds
will be used to pay debt owed to Slough. In the event that the rights offering
does not generate sufficient capital, 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 recently sold
interests in domestic exploration prospects and will continue to seek partners
in new and existing prospects.
Recent and planned 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. The
Company is
9
encouraged by developments with respect to agreements for future sales of its
gas from the Comet Ridge project. In late September, the Company entered into a
contract with Queensland Fertilizer Assets Ltd ("QFAL") of Queensland,
Australia, which provides that the Company 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. The Company has offered each
participant in the Comet Ridge project a pro-rata portion of the sales under the
QFAL contract. Based upon elections received to date and the level of
participation in the two existing ENERGEX contracts (in which the Company
participates 100% and 84%, respectively), the Company expects to sell most of
the contract volumes.
The Company had unrestricted cash and temporary investments of $2,136,000 as of
September 30, 2001, compared to $1,579,000 as of December 31, 2000. At
September 30, 2001, the Company had working capital of $4,191,000 compared to
working capital of $2,256,000 as of December 31, 2000. Working capital includes
restricted cash of $1,670,000 as of September 30, 2001 and $1,459,000 as of
December 31, 2000. The restricted cash as of September 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. The restricted cash at December 31, 2000 related to a letter of credit
securing the purchase of a drilling rig discussed below. During the nine months
ended September 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 $3,877,000 during the three months
ended September 30, 2001 compared to $2,119,000 of cash used during the same
period last year. The need to use cash for operations in both periods resulted
from the sale of most of the Company's U.S. oil and gas properties as of June
30, 2000.
During the nine months ended September 30, 2001, the Company had net receipts of
$14,430,000 from financing, which included borrowings of $10,000,000 from TCW
and $10,000,000 from Slough, and a $4,407,000 project-financing loan repayment
to Slough. Capital expenditures of $12,308,000 included $2,563,000 for the
purchase of a drilling rig which has been leased to a drilling contractor in
Queensland, Australia (discussed below), $4,779,000 for drilling costs in the
Comet Ridge project, $531,000 for drilling costs on other ATP's in Australia,
$1,074,000 for drilling costs in the Hanna Basin project and $367,000 for
drilling costs in the West Buna field. The Company's share of costs to drilling
two wells in the Lay Creek project was $475,000. Of this increase in the full
cost pool, $192,000 is included in capital expenditures and $283,000 is included
in payables as of September 30, 2001. The Company also incurred $2,214,000 in
capital costs related to Colorado leasehold acreage acquisitions. During the
nine months ended September 2001, the Company increased its interest in the
Comet Ridge coalbed methane project in Queensland Australia from 62.25% to 65%.
In June 2001, the Company acquired a 2.5% capital-bearing interest for
$1,688,000. The purchase price 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. The Company acquired an additional
.25% interest in the Comet Ridge project for approximately $169,000 in cash
during August 2001. Proceeds of $2,340,000 from asset sales during the nine
months ended September 30, 2001 were from the sale to Koch of a 50% interest in
the Lay Creek project in Colorado. The Company received approximately $2 million
from Koch at closing and has received or billed $480,000 for costs related to
the wells recently drilled at Lay Creek. Approximately $1.5 million, currently
shown as long-term receivables, must be paid to the Company by Koch through the
reimbursement of drilling costs or in cash on or before October 4, 2002.
During the nine months ended September 30, 2000, the Company 's $7,929,000
investment in property plant and equipment, included the acquisition of
additional interests totaling 6.5% in the Comet Ridge project for approximately
$3.3 million in cash and 1,463,328 shares of the Company's common stock.
Additionally, the Company had capital expenditures of approximately $4.0 million
in drilling and development costs in the Comet Ridge project during the nine
months ended September 30, 2001. The Company received approximately $16,600,000
from the sale of domestic properties during this nine-month period. Net cash
used by financing activities was $5,949,000 and included $2,415,000 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 $7,978,000 to retire long-term
debt.
At December 31, 2000, the Company owed Slough $11,907,000, consisting of a
corporate loan of $7,500,000 and a project-financing loan of $4,407,000, 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 the
loan facility with TCW discussed below. Since December 31, 2000, the Company has
borrowed an
10
additional $7.5 million from Slough, increasing the amount owed to Slough to $15
million as of September 30, 2001. The promissory note for $15 million matures
March 31, 2003 and bears interest at the 90-day London Interbank Offered Rate
plus 3.5%. The interest rate was 6.09% at September 30, 2001. The Company
expects to repay this $15 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
$4,407,000, 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. 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 $966,000 of
costs incurred to obtain the TCW financing, which are likewise being amortized
to interest expense over the life of the loan.
In May and September 2001, the Company received from TCW additional loan
advances of $1.0 million and $1.5 million, respectively, to fund drilling costs
related to the 20-well drilling program. Of the $7.0 million remaining under
the credit facility, about $2.6 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. The Company borrowed $1.0
million in October and expects to obtain the remaining $1.6 million advance
prior to December 31, 2001, the expiration date for obtaining advances under the
loan agreement with TCW.
The Company 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 at the Company's estimated costs, the Company will have to obtain
capital to fund its share of the $5 million difference, or almost $3.1 million.
The Company intends to use proceeds from its rights offering to fund any costs
above its estimates. The wells in the 20-well drilling program to date have been
drilled and completed at an average cost of $740,000, which is slightly higher
than the operator's estimated costs per well.
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. The Company 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 the Company 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. The Company 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 the
Comet Ridge project and/or 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. The Lessee also received a two-year
option to buy the rig and related equipment at TOGA's net cost. This drilling
rig was used on the three wells most recently drilled in the 20-well drilling
program on the Comet Ridge project. The Company as well as other participants in
the Comet Ridge project have benefited from reduced drilling costs with the use
of this rig. The Company has recorded a receivable of $75,000 for rent due from
the lessee as of September 30, 2001.
In January 2001, Slough advanced the Company $2,500,000 to finance the purchase
of the drilling rig. This loan bears interest at a rate of 10% per annum.
Payments are due monthly for all rents TOGA receives from the drilling
contractor during the
11
month and for accrued interest on the balance of the loan. As of September 30,
2001, the current portion of this loan was $155,000 which includes $75,000 of
rent due from the lessee on that date and $80,000 of rent estimated to be due
the Company in the near term.
Results of Operations - Comparison of the Three Months Ended September 30, 2001
and 2000
The Company incurred a net loss of $1,590,000 for the three months ended
September 30, 2001, compared to a net loss of $1,449,000 for the three months
ended September 30, 2000. The net loss in both periods is attributable to
reduced revenues due to the sale of most of the Company's producing properties
in the U.S. during 2000. The table below provides a comparison of operations for
the three months ended September 30, 2001 with those of the prior year's
quarter.
Three Months Ended
September 30 September 30 Increase % Increase
2001 2000 (Decrease) (% Decrease)
------------ ------------ ---------- ------------
Worldwide operations:
Operating Revenue $ 881,000 $ 878,000 $ 3,000 0%
Gas Volumes (Mcf) 689,000 478,000 211,000 44%
Oil Volumes (Bbls) 2,600 8,000 (5,400) (68%)
Average Gas Price per Mcf $ 1.19 $ 1.37 $ (0.18) (13%)
Average Oil Price per Bbl $ 24.10 $ 27.97 $ (3.87) (14%)
Operating Expense $ 500,000 $ 456,000 $ 44,000 10%
Average Lifting Cost per Mcf Equivalent ("Mcfe") $ 0.81 $ 0.90 $ (0.09) (10%)
General and Administrative $1,029,000 $1,100,000 $ (71,000) (6%)
Depreciation, Depletion and Amortization ("DD&A") $ 242,000 $ 220,000 $ 22,000 10%
DD&A Rate per Mcfe volumes sold $ 0.34 $ 0.42 $ (0.07) (18%)
Interest Expense $ 810,000 $ 312,000 $ 498,000 160%
Income tax expense (benefit) $ - $ (340,000) $ 340,000 100%
Domestic operations:
Operating Revenue $ 133,000 $ 343,000 $(210,000) (63%)
Gas Volumes (Mcf) 23,000 34,000 (11,000) (32%)
Oil Volumes (Bbls) 2,600 8,000 (5,400) (68%)
Average Gas Price per Mcf $ 3.06 $ 3.51 $ (0.45) (13%)
Average Oil Price per Bbl $ 24.10 $ 27.97 $ (3.87) (14%)
Operating Expense $ 132,000 $ 65,000 $ 67,000 103%
Average Lifting Cost per Mcfe $ 3.42 $ 0.79 $ 2.63 331%
DD&A $ 51,000 $ 75,000 $ (24,000) (32%)
DD&A rate per Mcfe volumes sold $ 1.32 $ 0.91 $ 0.41 44%
Australia operations:
Operating Revenue $ 748,000 $ 535,000 $ 213,000 40%
Gas Volumes (Mcf) 666,000 444,000 222,000 50%
Average Gas Price per Mcf $ 1.12 $ 1.20 $ (0.08) (7%)
Operating Expense $ 368,000 $ 391,000 $ (23,000) (6%)
Average Lifting Cost per Mcf $ 0.55 $ 0.88 $ (0.33) (37%)
DD&A $ 191,000 $ 145,000 $ 46,000 32%
DD&A rate per Mcf volumes sold $ 0.29 $ 0.33 $ (0.04) (12%)
12
As the Company's sale of producing properties was substantially complete by June
30, 2000, the comparison of the three months ended September 30, 2001 to the
prior year period provides a comparison of production from existing oil and gas
properties.
Domestic oil and gas volumes experienced significant declines due to normal
production declines and poor performance from several wells in the West Buna
field. The Company is participating in the workover of one of these wells in an
effort to improve the well's production. The Company has participated in
drilling two wells which are expected to add approximately 300 Mcf to the
Company's domestic daily production during the fourth quarter of 2001. The
Company may elect to participate in future drilling or workovers in an effort to
improve West Buna field production. Domestic revenues were also impacted by a
14% and 13% decrease in oil and gas prices, respectively. Operating expense and
lifting cost per Mcfe was significantly higher for the Company's domestic
operations as approximately $97,000 was attributable to wells being tested on
the Company's Hanna Basin acreage. Operating expenses were first incurred on the
Company's Hanna Basin acreage in December of 2000. Without these Hanna Basin
expenses operating expenses would have decreased by $30,000 rather than
increasing by $67,000. Operating expenses and lifting costs per Mcfe were also
increased by non-recurring workover expenses in the West Buna field totaling
$25,000. Domestic DD&A costs decreased significantly due to sales volume
reductions discussed previously.
Australian gas volumes increased by 50% due to development drilling and
increased gas volumes from existing wells. Operating revenue increased less than
did gas volumes in Australia as the average reported gas price decreased by 7%
due to lower exchange rates. Operating expense in Australia decreased by 6% as
the Company benefited from lower then expected fuel costs. Australian DD&A costs
increased consistently with increases reported in sales volumes; however, the
DD&A rate per Mcf decreased. The DD&A rate improved because sales volumes
increased proportionately faster than did total volumes produced, which are used
to calculate DD&A.
Interest expense increased $498,000 primarily as a result of approximately
$400,000 in expenses associated with the amortization of deferred loan costs
associated with the TCW Credit agreement. The Company capitalized approximately
$60,000 of interest expense and interest expense increased by an additional
$158,000 due to increasing debt balances.
The income tax benefit in the quarter ended September 30, 2000 was due to the
reversal of the current income tax expense in prior quarters.
Results of Operations - Comparison of the Nine Months Ended September 30, 2001
and 2000
The Company incurred a net loss of $4,582,000 for the nine months ended
September 30, 2001, compared to net income of $349,000 for the nine months ended
September 30, 2000. Net income during the prior year period included a gain of
$4,837,000 associated with the sale of most of the Company's domestic producing
properties. The loss reported for the first nine months of calendar 2001
resulted primarily from the loss of revenue from these properties. The table
below provides a comparison of operations for the nine months ended September
30, 2001 with those of the prior year's nine months.
Nine Months Ended
September 30 September 30 Increase % Increase
2001 2000 (Decrease) (% Decrease)
------------ ------------- ------------------- -----------------
Worldwide operations:
Operating Revenue $2,522,000 $5,705,000 $ (3,183,000) (56%)
Gas Volumes (Mcf) 1,780,000 1,722,000 58,000 3%
Oil Volumes (Bbls) 9,700 109,000 (99,300) (91%)
Average Gas Price per Mcf $ 1.27 $ 1.72 $ (0.44) (26%)
Average Oil Price per Bbl $ 26.88 $ 25.24 $ 1.64 6%
Operating Expense $1,618,000 $2,904,000 $ (1,286,000) (44%)
Average Lifting Cost per Mcf Equivalent ("Mcfe") $ 0.88 $ 1.22 $ (0.34) (28%)
General and Administrative $3,073,000 $3,063,000 $ 10,000 0%
Depreciation, Depletion and Amortization ("DD&A") $ 667,000 $1,229,000 $ (562,000) (46%)
DD&A Rate per Mcfe volumes sold $ 0.36 $ 0.52 $ (0.15) (30%)
Interest Expense $2,053,000 $1,118,000 $ 935,000 84%
Income tax expense (benefit) $ (1,000) $1,573,000 $ (1,574,000) (100%)
13
Nine Months Ended
September 30 September 30 Increase % Increase
2001 2000 (Decrease) (% Decrease)
--------------- --------------- ------------------- -----------------
Domestic operations:
Operating Revenue $ 616,000 $4,094,000 $ (3,478,000) (85%)
Gas Volumes (Mcf) 68,000 432,000 (364,000) (84%)
Oil Volumes (Bbls) 9,700 109,000 (99,300) (91%)
Average Gas Price per Mcf $ 5.22 $ 3.11 $ 2.12 68%
Average Oil Price per Bbl $ 26.88 $ 25.24 $ 1.64 6%
Operating Expense $ 434,000 $1,838,000 $ (1,404,000) (76%)
Average Lifting Cost per Mcfe $ 3.44 $ 1.69 $ 1.75 103%
DD&A $ 153,000 $ 721,000 $ (568,000) (79%)
DD&A rate per Mcfe volumes sold $ 1.21 $ 0.66 $ 0.55 83%
Australia operations:
Operating Revenue $1,906,000 $1,611,000 $ 295,000 18%
Gas Volumes (Mcf) 1,712,000 1,290,000 422,000 33%
Average Gas Price per Mcf $ 1.11 $ 1.25 $ (0.14) (11%)
Operating Expense $1,184,000 $1,066,000 $ 118,000 11%
Average Lifting Cost per Mcf $ 0.69 $ 0.83 $ (0.13) (16%)
DD&A $ 514,000 $ 508,000 $ 6,000 1%
DD&A rate per Mcf volumes sold $ 0.30 $ 0.39 $ (0.09) (24%)
Domestic oil and gas volumes decreased primarily due to the aforementioned sale
of oil and gas properties that was substantially complete by June 30, 2000.
Domestic revenues otherwise benefited from a 6% and 68% increase in oil and gas
prices, respectively. Operating expense was significantly lower for domestic
operations due to the sale of oil and gas properties. However, the average
lifting cost per Mcfe increased because of approximately $293,000 in costs
associated with wells currently being tested on the Hanna Basin acreage for
which there were no associated sales volumes. Operating expenses were first
incurred on the Hanna Basin acreage in December of 2000. Without these Hanna
Basin expenses operating expenses would have decreased by $1,697,000 and lifting
costs for the nine months ended September 30, 2001 would have been $1.10 per
Mcfe. Domestic DD&A costs decreased significantly due to sales volume decreases
discussed previously.
Australian gas volumes increased by 33% due to production from new wells drilled
in 2001 and to an increased rate of production from wells drilled in prior
years. Operating revenue in Australia increased less than did gas volumes
because of lower foreign exchange rates during the 2001 period. Operating
expenses in Australia experienced increases of 11% due to the increase in the
number of wells. The average increase in volumes caused a 16% decrease in
average lifting cost per Mcf. Australian DD&A costs were essentially flat;
however, the DD&A rate per Mcf decreased because of increasing reserve volumes
and because sales volumes increased proportionately faster than did total
volumes produced, which are used to calculate DD&A.
Interest expense increased $935,000 primarily as a result of approximately
$910,000 in expense associated with the amortization of deferred loan costs
associated with the TCW credit agreement. During the nine months ended
September 30, 2001, the Company also capitalized approximately $201,000 of
interest expense and interest expense increased by an additional $226,000 due to
increasing debt balances.
The income tax expense of $1,573,000 for the nine months ended September 30,
2000 resulted from the realization of the Company's deferred tax asset.
14
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 issued restricted common stock to an
unaffiliated third party for the acquisition of an additional 2.5%
capital-bearing interest in the Comet Ridge coalbed methane project in
Queensland, Australia. The purchase price of $1,688,000 was paid to
the seller with the issuance of 675,000 shares, 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
4.72 Promissory Note dated August 20, 2001, in the amount
of $15,000,000 issued by the Registrant to Slough
Estates USA Inc., filed as Exhibit 4.72 to Form 8-K
filed with the Commission on October 18, 2001, and
incorporated herein by reference.
4.73 First Amendment to Security Agreement dated August
20, 2001, between the Registrant and Slough Estates
USA Inc., filed as Exhibit 4.73 to Form 8-K filed
with the Commission on October 18, 2001, and
incorporated herein by reference.
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 to Form
S-3, SEC File No. 333-59052, filed with the
Commission on July 26, 2001, and incorporated herein
by reference.
10.81 Gas Sales Agreement between Tipperary Oil & Gas
(Australia) Pty Ltd (ACN 077 536 871) as Seller and
Queensland Fertilizer Assets Limited (ACN 011 062
294) as Buyer, dated September 28, 2001, filed as
Exhibit 10.81 to Form 8-K filed with the Commission
on October
15
18, 2001, and incorporated herein by reference.
10.82 Employment Agreement dated September 18, 2001 between
Registrant and David L. Bradshaw, filed as Exhibit
10.82 to Form 8-K filed with the Commission on
October 18, 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
16
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: November 14, 2001 By: /s/ David L. Bradshaw
-------------------------------------------
David L. Bradshaw, President, Chief
Executive Officer and Chairman of the
Board of Directors
Date: November 14, 2001 By: /s/ Lisa S. Wilson
-------------------------------------------
Lisa S. Wilson, Chief Financial Officer and
Principal Accounting Officer
17