UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 1999
----------------------
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
-------------- -------------
Commission File Number 1-7796
TIPPERARY CORPORATION
(Exact name of registrant as specified in its charter)
Texas 75-1236955
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
633 Seventeenth Street, Suite 1550
Denver, Colorado 80202
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (303) 293-9379
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
----- -----
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Class Outstanding at May 17, 1999
- ---------------------------- ---------------------------
Common Stock, $.02 par value 15,133,955 shares
TIPPERARY CORPORATION AND SUBSIDIARIES
Index to Form 10-Q
Page No.
PART I. FINANCIAL INFORMATION (UNAUDITED)
Item 1. Financial Statements
Consolidated Balance Sheet
March 31, 1999 and September 30, 1998 1
Consolidated Statement of Operations
Three months and six months ended
March 31, 1999 and 1998 2
Consolidated Statement of Cash Flows
Six months ended March 31, 1999 and 1998 3
Notes to Consolidated Financial Statements 4-6
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations 7-12
Item 3. Quantitative and Qualitative Disclosure about
Market Risk 13
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 14
Item 2. Changes in Securities 14
Item 3. Defaults Upon Senior Securities 14
Item 4. Submission of Matters to a Vote of Security Holders 14
Item 5. Other Information 14
Item 6. Exhibits and Reports on Form 8-K 14
SIGNATURES 15
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
TIPPERARY CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheet
(in thousands)
March 31, September 30,
1999 1998
------------- -------------
(unaudited)
ASSETS
Current assets:
Cash and cash equivalents $ 959 $ 633
Receivables 1,204 1,408
Inventory 217 218
Other current assets 117 66
------------- -------------
Total current assets 2,497 2,325
------------- -------------
Property, plant and equipment, at cost:
Oil and gas properties, full cost method 132,272 136,647
Other property and equipment 2,591 2,571
------------- -------------
134,863 139,218
Less accumulated depreciation, depletion and
amortization (94,437) (92,626)
------------- -------------
Property, plant and equipment, net 40,426 46,592
------------- -------------
Noncurrent portion of deferred income taxes, net 1,573 1,573
Other noncurrent assets 120 270
------------- -------------
$ 44,616 $ 50,760
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 919 680
Accrued liabilities 237 341
Production taxes payable 92 103
Royalties payable 196 156
------------- -------------
Total current liabilities 1,444 1,280
------------- -------------
Long-term debt 11,800 16,500
Long-term note payable - related party 6,500 2,700
Commitments and contingencies (Note 6)
Minority interest 572 -
Stockholders' equity
Common stock; par value $.02; 20,000,000
shares authorized; 15,161,755 issued and
15,133,955 outstanding in March; 13,161,755
issued and 13,133,955 outstanding in
September 303 263
Capital in excess of par value 107,988 105,564
Accumulated deficit (83,920) (75,476)
Treasury stock, at cost; 27,800 shares (71) (71)
------------- -------------
Total stockholders' equity 24,300 30,280
------------- -------------
$ 44,616 $ 50,760
============= =============
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
March 31, March 31,
------------------- -------------------
1999 1998 1999 1998
---- ---- ---- ----
Revenues $ 1,608 $ 2,244 $ 3,357 $ 4,808
Costs and expenses:
Operating 1,115 1,188 2,260 2,451
General and administrative 566 453 1,238 882
Depreciation, depletion and
amortization 720 984 1,880 1,945
Write-down of oil and gas
properties - - 5,727 -
-------- -------- -------- --------
Total costs and expenses 2,401 2,625 11,105 5,278
-------- -------- -------- --------
Operating loss (793) (381) (7,748) (470)
Other income (expense):
Interest income 4 6 8 22
Interest expense (350) (330) (764) (551)
Foreign currency exchange
gain (loss) (4) - 22 -
-------- -------- -------- --------
Total other expense (350) (324) (734) (529)
-------- -------- -------- --------
Loss before income
taxes (1,143) (705) (8,482) (999)
Income tax expense - - - -
-------- -------- -------- --------
Net loss before minority interest (1,143) (705) (8,482) (999)
Minority interest in loss of
subsidiary 35 - 38 -
-------- -------- -------- --------
Net loss $ (1,108) $ (705) $ (8,444) $ (999)
======== ======== ======== ========
Net loss per share -
basic and diluted $ (.07) $ (.05) $ (.59) $ (.08)
======== ======== ======== ========
Weighted average shares
outstanding 15,134 13,122 14,233 13,103
======== ======== ======== ========
See accompanying notes to consolidated financial statements.
2
TIPPERARY CORPORATION AND SUBSIDIARIES
Consolidated Statement of Cash Flows
(in thousands)
(unaudited)
Six months ended
March 31,
-------------------------
1999 1998
---------- ----------
Cash flows from operating activities:
Net loss $ (8,444) $ (999)
Adjustments to reconcile net loss to net cash
provided by (used in) operating activities:
Depreciation, depletion and amortization 1,880 1,945
Write-down of oil and gas properties 5,727 -
Minority interest in loss of subsidiary (38) -
Change in assets and liabilities:
Decrease in receivables 204 541
(Increase) decrease in inventory 1 (21)
Increase in other current assets (51) (106)
Increase (decrease) in accounts payable,
accrued liabilities and production
taxes payable 124 (655)
Decrease in advances from joint owners - (165)
Increase (decrease) in royalties payable 40 (4)
Other - (4)
---------- ----------
Net cash provided by (used in) operating
activities (557) 532
---------- ----------
Cash flows from investing activities:
Proceeds from asset sales 705 1,456
Capital expenditures (2,077) (6,037)
---------- ----------
Net cash used in investing activities (1,372) (4,581)
---------- ----------
Cash flows from financing activities:
Proceeds from borrowing 3,800 1,300
Principal repayments (4,700) -
Proceeds from issuance of stock 2,239 184
Proceeds from subsidiary sale of stock 610 -
Proceeds from issuance of warrants 310 -
Payments for debt and equity financing (4) -
---------- ----------
Net cash provided by financing activities 2,255 1,484
---------- ----------
Net increase (decrease) in cash and cash
equivalents 326 (2,565)
Cash and cash equivalents at beginning of period 633 3,529
---------- ----------
Cash and cash equivalents at end of period $ 959 $ 964
========== ==========
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest $ 652 $ 632
Income taxes $ - $ -
See accompanying notes to consolidated financial statements.
3
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(unaudited)
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
- ---------------------
In the opinion of management, the accompanying unaudited 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 March 31, 1999,
and the results of its operations for the three-month and six-month periods
ended March 31, 1999 and 1998. 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., and its share
of assets, liabilities, revenues and expenses of unincorporated joint ventures
and partnerships. The accounting policies followed by the Company are included
in Note 1 to the Consolidated Financial Statements in the Annual Report on Form
10-K for the year ended September 30, 1998. These financial statements should
be read in conjunction with the Form 10-K.
Impact of New Accounting Pronouncements
- ---------------------------------------
In June 1998, the FASB issued Statement of Financial Accounting Standards No.
133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS
133"). This statement is effective for all fiscal quarters of fiscal years
beginning after June 15, 1999, and will be adopted by the Company effective
October 1, 1999. SFAS 133 requires companies to report the fair market value of
derivatives on the balance sheet and record in income or other comprehensive
income, as appropriate, any changes in the fair value of the derivative. The
Company does not believe that adoption of this SFAS 133 will have a material
impact on its financial statements.
NOTE 2 - WRITE-DOWN OF OIL & GAS PROPERTIES
During the six-month period ended March 31, 1999, the Company recorded a
$5,727,000 write-down of its U.S. oil and gas properties. Under the full cost
method of accounting, capitalized oil and gas property costs, less accumulated
amortization and related deferred income taxes, may not exceed the present value
of future net revenues from proved reserves discounted at 10%, plus the lower of
cost or market value of unproved properties, less related income tax effects.
This "ceiling test" must be performed quarterly on a country-by-country basis.
Based on December 31, 1998 oil and gas prices, the Company's domestic full cost
pool book value exceeded its ceiling test value by $5,727,000. Accordingly, the
book value of the Company's oil and gas properties was written down by this
amount as of December 31, 1998.
4
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(unaudited)
NOTE 3 - RELATED PARTY TRANSACTIONS
On December 22, 1998, the Company closed a transaction involving debt and equity
financing of $11,700,000 provided by Slough Estates USA Inc. ("Slough"), the
Company's largest shareholder. This financing was comprised of a loan
commitment for $6,000,000 to be used for development of the Comet Ridge project
in Australia; $4,000,000 from the issuance of 2,000,000 shares of restricted
common stock and asset sales; and an additional loan in the amount of
$1,700,000.
The commitment for the $6,000,000 loan was made to the Company's Australian
subsidiary. When received, the proceeds from this loan are to be used to fund
the drilling of eight wells and to expand the gathering system on the Comet
Ridge project. The loan is evidenced by a five-year note bearing interest at
the rate of 10% per annum. The terms of the note also provide that Slough will
receive additional payments based upon a contractual payment right to 7% of the
gross revenues from both the existing and eight proposed wells until the loan
is paid in full, after which it will be on the eight new wells for the life of
those wells. Subsequent to March 31, 1999, the Company's Australian subsidiary
received approximately $275,000 advanced on this loan for the initial costs of
this drilling program.
The shares of the Company's common stock were issued to Slough at a premium over
the market value on the date of closing. Of the $4,000,000 received by the
Company, $2,239,000 was recorded as proceeds from the issuance of common stock,
net of equity financing costs of $136,000, and the premium of $1,625,000 was
recorded as proceeds attributable to other assets acquired by Slough in the
transaction. Approximately $705,000 of the premium was allocated to the value
of the contractual payment right and was treated as a sale of a portion of the
Company's share of reserves in the Comet Ridge project. In accordance with the
requirements of the full cost method of accounting, the Australian full cost
pool was reduced by this amount. In connection with this transaction, the
Company issued to Slough ten percent of the common stock of the Australian
subsidiary and a warrant to purchase up to 500,000 shares of the Company's
common stock at $3.00 per share, exercisable during a five-year period
beginning in December 2000 and ending in December 2005. The remainder of the
premium was assigned to the warrant and to the common stock of the subsidiary
in the amounts of $310,000 and $610,000, respectively.
The loan of $1,700,000 was consolidated with previous loans from Slough into a
total note payable of $5,500,000 as of December 31, 1998. The $1,700,000
proceeds from this loan and the $4,000,000 proceeds from the issuance of common
stock and sale of assets were used to reduce the Company's bank debt by
$4,700,000 which reduced the loan balance due the bank to $11,800,000. The
remaining $1,000,000 of the proceeds from the financing was retained by the
Company for capital expenditures and working capital. On March 11, 1999, the
Company borrowed from Slough an additional $1,000,000 and executed a new three-
year note for $6,500,000. The loan agreement provides for interest to be paid
quarterly at the London Interbank Offered Rate plus 3.5%.
NOTE 4 - MINORITY INTEREST IN SUBSIDIARY
Effective December 22, 1998, the Company issued to Slough ten percent of the
common stock of its Australian subsidiary in accordance with the terms of the
previously described debt and equity financing transaction. See Note 3. The
resulting non-Company owned shareholder interest has been accounted for as a
minority interest in the accompanying Consolidated Financial Statements.
5
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(unaudited)
NOTE 5 - LOSS PER SHARE
The following table sets forth the computation of basic and diluted loss per
share (in thousands except per share data):
Three months ended Six months ended
March 31, March 31,
------------------ ------------------
1999 1998 1999 1998
------- ------- ------- -------
Numerator:
for basic and diluted net
-------------------------
loss per share -
--------------
net loss $(1,108) $ (705) $(8,444) $ (999)
Denominator:
for basic net loss per
----------------------
share - weighted average
-----
shares outstanding 15,134 13,122 14,233 13,103
for diluted net loss
--------------------
per share - adjusted weighted
---------
average shares outstanding
and assumed conversion of
dilutive option shares 15,134 13,122 14,233 13,103
Basic loss per share $ (0.07) $ (0.05) $ (0.59) $ (0.08)
======= ======== ======= ========
Diluted loss per share $ (0.07) $ (0.05) $ (0.59) $ (0.08)
======= ======== ======= ========
Potentially dilutive common stock shares from the exercise of options and
warrants were antidilutive for the three and six-month period ended March 31,
1999 and 1998, and therefore were not included in the computation of loss per
share.
NOTE 6 - COMMITMENTS AND CONTINGENCIES
The Company is plaintiff in a lawsuit filed on August 6, 1998, styled TIPPERARY
CORPORATION AND TIPPERARY OIL & GAS (AUSTRALIA) PTY LTD. V. TRI-STAR PETROLEUM
COMPANY, Cause No. CV42,265, in the District Court of Midland County, Texas.
The complaint, which concerns the Comet Ridge coalbed methane project in
Queensland, Australia, alleges that Tri-Star Petroleum Company ("Tri-Star"),
operator of the project, has failed to perform its duties under the operating
agreement, and seeks the removal of Tri-Star as operator, an accounting of
expenses charged to the joint interest account and unspecified amounts for
damages for breach of contract. Among the allegations in the complaint are that
Tri-Star has refused to allow the Company to inspect the books and records of
the project, has attempted to block the Company's right to take its
proportionate share of gas production in kind, may have improperly billed
expenses to the joint interest owners and has an impermissible conflict of
interest precluding it from acting as a reasonable and prudent operator.
Tri-Star has answered the complaint denying the claims and has filed a
counterclaim alleging that the Company has breached the operating agreement and
interfered with prospective contracts and business relations. Two additional
non-operating joint interest owners recently intervened in the action as
plaintiffs, asserting a claim for the removal of Tri-Star as operator, and
other claims similar to those asserted by the Company. Discovery is in
process.
On March 14, 1997, the Company filed a complaint along with several other
plaintiffs in BTA OIL PRODUCERS, ET AL. V. MDU RESOURCES GROUP, INC., ET AL. in
Stark County Court in the Southwest Judicial District of North Dakota. The
plaintiffs are suing the defendants for breach of gas sales contracts, unjust
enrichment, implied trust and related business torts. The case concerns the
sale by plaintiffs and certain predecessors of natural gas processed at the
McKenzie Gas Processing Plant in North Dakota to Koch Hydrocarbons Company. It
also concerns the contracts for resale of that gas to MDU Resources Group, Inc.
and Williston Basin Interstate Pipeline Company. The defendants have answered
the complaint denying the claims, and discovery is in process.
6
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Information herein contains forward-looking statements within the meaning of the
Private Securities Litigation Reform Act of 1995, which can be identified by
words such as "may," "will," "expect," "anticipate," "estimate" or "continue,"
or comparable words. 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.
Readers are encouraged to read the SEC reports of the Company, particularly its
Form 10-K for the Fiscal Year Ended September 30, 1998, for meaningful
cautionary language disclosing why actual results may vary materially from those
anticipated by management.
OVERVIEW
Tipperary Corporation and its subsidiaries are principally engaged in the
production and development of and exploration for crude oil and natural gas.
The Company's major areas of operations are in the Permian Basin, Rocky Mountain
and Mid-Continent areas of the United States, and in Queensland, Australia,
where it is involved in the development of a coalbed methane project. The
Company seeks to increase its oil and gas reserves through exploration,
exploitation and development projects and occasionally through the purchase of
producing properties.
FINANCIAL CONDITION, LIQUIDITY AND CAPITAL RESOURCES
The Company had cash and temporary investments of $959,000 as of March 31, 1999
compared to $633,000 as of September 30, 1998. At March 31, 1999, the Company
had working capital of $1,053,000 compared to working capital of $1,045,000 as
of September 30, 1998. In recent years, the Company's primary sources of
funding have been operating cash flows, debt and equity financing and sales of
non-core producing properties. During the six months ended March 31, 1999, cash
flows were provided by sales of assets to and debt and equity financing from
Slough Estates USA Inc. ("Slough"), the Company's largest shareholder. These
proceeds were used to reduce bank debt and for capital expenditures and
operating activities.
Net cash used in operating activities was $557,000 during the first six months
of fiscal 1999 compared to $532,000 provided by operating activities during the
corresponding period in the prior year. The increase in net cash used in
operating activities was attributable to lower oil production volumes and
significantly lower U.S. oil and gas prices in the six months ended March 31,
1999, as compared to the prior fiscal year period.
During the six months ended March 31, 1999, net cash provided by financing
activities was $2,255,000. Total borrowings of $3,800,000 included $1,700,000
received from Slough in connection with the financing transaction which closed
in December 1998 (see Note 3 to the Consolidated Financial Statements herein),
and other loans from Slough received during the current fiscal year totaling
$2,100,000. In connection with the December 1998 financing transaction, the
Company also received $4,000,000 from the issuance of 2,000,000 shares of the
Company's common stock to Slough. Since these shares were issued at a premium
over the market value of the stock on the date of closing, $2,239,000 was
recorded as proceeds from the issuance of common stock, net of equity financing
costs of $136,000, and the premium of $1,625,000 was attributable to other
assets acquired by Slough in the transaction. Of the total $1,625,000 proceeds,
$705,000 was for contractual payment rights to revenue from the Australian
reserves, $610,000 was for the minority interest in the Australian subsidiary,
and $310,000 was for a warrant Slough received to acquire restricted shares of
the Company's common stock. The total cash proceeds from this transaction with
Slough were $5,700,000. The Company used $4,700,000 to reduce bank debt and
$1,000,000 for capital expenditures and working capital. Additional borrowings
in the amount of $2,100,000 have also been used to fund capital expenditures.
During the six months ended March 31, 1998, net cash provided by financing
activities of $1,484,000 included additional bank borrowings of $1,300,000 and
$184,000 of proceeds received in connection with the issuance of 50,000 shares
of the Company's common stock to a former director pursuant to the exercise of
warrants and the issuance of 30,584 common shares to employees pursuant to the
1987 Employee Stock Option Plan.
During the six months ended March 31, 1999, the Company incurred capital
expenditures of $2,077,000 and received proceeds of $705,000 for the contractual
payment right to revenue from the Comet Ridge project discussed above. A total
of approximately $1,777,000 was expended for the Comet Ridge project. Costs of
approximately $300,000 were attributable to seismic data gathering activities.
Two additional wells were drilled and cased and are awaiting
7
completion. The Company's share of the costs to drill these wells was
approximately $400,000. Of the remaining expenditures in the Comet Ridge area,
approximately $210,000 was invested in well equipment inventory and in the gas
gathering facility and $557,000 was expended for other capital items. Capital
expenditures related to disputed billings totaling approximately $310,000 have
been paid to the 238th Judicial District Court of Midland County, Texas, in the
litigation with Tri-Star Petroleum Company. See Note 6 to the Consolidated
Financial Statements herein. Year-to-date capital expenditures for domestic
operations of approximately $300,000 included $79,000 for the purchase of
additional interests in two of the Company's operated wells, non-producing
leasehold costs of $54,000 and development costs and other capital expenditures
of $167,000.
During the six months ended March 31, 1998, the Company incurred capital
expenditures of $6,037,000 and received proceeds of $1,456,000 from a sale of
producing properties, resulting in net cash used in investing activities of
$4,581,000. The capital expenditures included an investment of $4,493,000 in
the Comet Ridge coalbed methane project in Queensland, Australia and $1,544,000
in domestic exploration and other costs. The Comet Ridge project expenditures
at March 31, 1998, of $4,493,000 included approximately $3,200,000 toward the
purchase of an additional 5% interest in the project which increased the
Company's interest to 55.75% of capital costs and 52.20% of operating expenses,
and its net revenue interest to 46.22% prior to project payout. Subsequent to
payout, the Company's interest is 45.35% of costs and 39.99% of revenues. Costs
for gas gathering and compression charges and other capital items totaled
$1,293,000. Domestic capital expenditures of $1,544,000 in the fiscal 1998
period included exploration costs of approximately $987,000, non-producing
leasehold acquisition costs of approximately $331,000 and other capital
expenditures of $226,000. The Company's domestic exploration activities were
focused in the Williston Basin of Montana and North Dakota.
The Company in recent years has hedged a portion of its oil production to
provide a minimum weighted average sales price. The Company has entered into
several swap agreements which provide a hedge on an average of approximately
55% of its projected oil production for the months of April through July 1999.
Swap agreements covering 20,000 barrels of oil per month for April and May were
entered into with an average NYMEX floor price of $14.85 per barrel. The
Company has hedged 15,000 barrels of June production and 10,000 barrels of July
production at an average NYMEX price of $16.32 and $17.68 per barrel,
respectively. The Company's actual price received for oil at the wellhead
during the six months ended March 31, 1999, was $2.73 per barrel below the
average NYMEX oil price. The Company received net payments related to its
hedging activities of $23,000 during the six months ended March 31, 1999, as
compared to $253,000 for the corresponding period in the prior fiscal year. Of
the total payments received in the first six months of fiscal 1998, $22,000 was
received during the first quarter and $231,000 was received during the second
quarter. The $23,000 received during fiscal 1999 was received during the first
quarter with no production hedged during the second quarter.
The Company's bank credit agreement (the "agreement") contains provisions for
both fixed rate and variable rate borrowings. The loan agreement, as amended,
provides for a two-tranche revolver with interest at either the London Interbank
Offered Rate ("LIBOR") plus 2.5%, or the bank's Base Rate on the first
$12,000,000 and either LIBOR plus 3.8% or the bank's Base Rate plus 1% on the
remainder. The LIBOR-based option may be selected for periods not exceeding 90
days. The outstanding bank debt at March 31, 1999 of $11,800,000 was under
LIBOR loans. At September 30, 1998, the Company had outstanding bank debt of
$16,500,000 under both LIBOR and Base Rate loans. The weighted average interest
rate was 7.44% as of March 31, 1999, and 8.48% as of September 30, 1998. Upon
expiration of the revolver (the "Conversion Date"), the principal balance will
convert to a three-year term loan. The Conversion Date was recently extended by
the bank from October 5, 1999 to October 5, 2000.
Certain of the Company's domestic oil and gas properties have been pledged as
security for the bank loan, and the Company recently pledged other unencumbered
properties at the request of the bank. The maximum borrowing base is determined
solely by the bank and is based upon its assessment of the value of the
Company's properties. This bank valuation is based upon the bank's assumptions
about reserve quantities, oil and gas prices, operating expenses and other
assumptions, all of which may change from time to time and which may differ from
the Company's assumptions. At March 31, 1999, the borrowing base was
$11,800,000. The borrowing base is subject to redetermination semi-annually
and based on discussions with the bank, the Company anticipates a substantial
reduction in the borrowing base during the third quarter of fiscal 1999. This
anticipated reduction is primarily a result of the recent low product prices.
The agreement provides that the Company cure a borrowing base deficiency within
30 days; however, the bank may provide the Company an extension of time in which
to do so. The deficiency would have to be cured by reducing the principal
balance of the outstanding loan to an amount equal to or less than the borrowing
base, since no additional collateral is
8
available to increase the borrowing base. The Company has not yet determined
how it will eliminate the anticipated borrowing base deficiency, but has begun
evaluating its options, which include a re-financing or substantial sale of
assets.
Due to the severe decline in oil and gas prices, the Company recorded a non-cash
write-down of its United States full cost pool as of December 31, 1998, in the
amount of $5,727,000. Price declines during the first quarter of fiscal 1999
caused a significant reduction of estimated future net revenues associated with
the Company's reserves. Under the full cost method of accounting, capitalized
oil and gas property costs, less accumulated amortization and related deferred
income taxes, may not exceed the present value of future net revenues from
proved reserves, plus the lower of cost or market value of unproved properties,
less related taxes. This "ceiling test" is performed quarterly. Based on oil
and gas prices at December 31, 1998, the Company's full cost pool exceeded the
calculated "ceiling test" value by $5,727,000. Accordingly, the book value of
the Company's oil and gas properties was written down by this amount as of
December 31, 1998.
Extremely low oil and gas prices during the six months ended March 31, 1999,
resulted in negative operating cash flows and caused the Company to shut in
approximately 10% of its operated domestic oil and gas production and to reduce
general and administrative expenses. A 20% staff reduction and reduction in
other expenses resulted in a 25% decrease in budgeted general and administrative
expenses, excluding litigation costs associated with the Comet Ridge project.
The effect of these reductions should be realized beginning with the third
quarter of fiscal 1999. Cash compensation paid during a three-month period
ended April 30, 1999, was also reduced as certain Company officers accepted a
portion of their compensation in the form of restricted shares of the Company's
common stock. While oil and gas prices have improved significantly since March
31, 1999, management continues to monitor general and administrative expenses
in an effort to improve operating cash flows. Improved cash flows subsequent
to March 31, 1999, resulting from increased prices, are currently being
partially offset by lower production volumes resulting from natural production
declines and from wells that were shut in during the six months ended March 31,
1999. The Company continues to evaluate its general and administrative expenses
and the economics of its domestic oil and gas production in an effort to
maximize operating cash flows.
As discussed above, the Company may seek new financing or a sale of assets to
cure the anticipated substantial borrowing base reduction. The Company's
ability to fund the current minimal level of capital expenditures both
domestically and in Australia will depend not only on how bank debt is
reduced, but also on the Company's ability to generate positive cash flow
from its operations. An eight-well drilling program on the Comet Ridge
coalbed methane project will be financed with the proceeds from a $6,000,000
loan commitment from Slough. Subsequent to March 31, 1999, Slough advanced
approximately $275,000 for the initial costs of this drilling program. See
Note 3 to the Consolidated Financial Statements herein. Management believes
positive cash flows could result in the near term with current oil and gas
prices and production levels. In addition, if the Company is successful in
causing a reduction in operating and litigation expenses of the Comet Ridge
project, cash flows could improve significantly. In order to replace
reserves in the United States, additional financing would likely be
necessary. However, to the extent that development drilling in the Comet
Ridge project is successful, management anticipates that additional revenues
from gas sales could alleviate the need for such financing.
YEAR 2000
The following information constitutes a "Year 2000 Readiness Disclosure" for
purposes of the Year 2000 Information and Readiness Disclosure Act.
The year 2000 compliance issue, which is common to most companies, concerns the
inability of computer information systems to properly recognize and process
date-sensitive information as the year 2000 approaches. This could result in
errors in information or significant system failures causing disruptions of
normal business operations. The Company is in the process of evaluating its
computer information and communication systems for Year 2000 readiness and has
hired an outside consulting firm to advise and assist the Company with this
compliance project.
The Company expects to resolve all issues relating to reprogramming, replacing
and testing the affected computer systems prior to September 1, 1999, so that
they are year 2000 compliant. To this end, the Company upgraded its core
management information system during February 1999. The Company's management
information software applications have been modified and certified to be year
2000 compliant by its software vendor. This modified software was
9
installed in March 1999. An on-site testing program is in process and is
expected to be completed by June 30, 1999. In addition, the Company is
currently conducting an inventory, review and assessment of its desktop
computers, networks, servers and software applications to determine whether they
are year 2000 compliant. Management is also reviewing internal non-information
technology systems for year 2000 readiness and believes that they are year 2000
compliant.
The Company has begun the process of contacting significant suppliers,
purchasers, financial institutions, and other key business partners to
ascertain their year 2000 readiness and to assess the extent to which the
Company's operations may be impacted should those organizations fail to properly
update their computer systems. The Company cannot assure that there will not
be material adverse effects if these third parties fail to convert their systems
in a timely manner and currently believes this to be its most significant risk
relating to the year 2000 issue. In order to mitigate the risk of potential
failure of third parties to achieve year 2000 compliance, contingency plans
will be developed.
Compliance costs incurred to date have not been material and the total cost of
the year 2000 project is not expected to be material. Funding has been and will
continue to be provided by operating cash flows and expensed as incurred. Time
and cost estimates are based on currently available information. Actual results
could differ materially from these estimates.
RESULTS OF OPERATIONS - COMPARISON OF THE THREE MONTHS ENDED MARCH 31, 1999, AND
1998
The Company reported a net loss of $1,108,000 for the three months ended March
31, 1999, compared to net loss of $705,000 for the three months ended March 31,
1998. Operating losses increased $412,000 to a loss of $793,000 in the fiscal
1999 quarter from an operating loss of $381,000 in the corresponding quarter of
fiscal 1998. The increase in operating losses is primarily due to
significantly lower oil and gas prices received during the three months ended
March 31, 1999, as compared to the prior year quarter. Following are detailed
comparisons of the components of the respective periods.
Operating revenues for the three months ended March 31, 1999, decreased
$636,000, or 28%, to $1,608,000 from $2,244,000 in the corresponding fiscal 1998
quarter. Oil volumes produced during the second fiscal 1999 quarter decreased
19,000 barrels, or 18%, to 84,000 barrels versus 103,000 barrels in the prior
year quarter, decreasing revenue by $294,000. Gas volumes sold from the
Company's U.S. properties increased 22,000 Mcf, or 7%, to 336,000 Mcf in the
current quarter compared to 314,000 Mcf in the three months ended March 31,
1998, resulting in a $39,000 increase in revenue. The oil volume decrease was
the result of production curtailments in response to low oil prices and natural
production declines that occur over the lives of producing wells. The increase
in gas volumes was attributable to favorable gas balancing adjustments in the
fiscal quarter ended March 31, 1999. Average oil prices decreased 33% to $10.32
per barrel for the three months ended March 31, 1999, from $15.45 per barrel for
the corresponding prior year quarter, resulting in a $431,000 decrease in
revenue. Domestic gas prices decreased 18% to $1.43 per Mcf in the current year
quarter versus $1.75 in the prior year quarter, resulting in a $108,000 revenue
decrease. Sales from the Company's Comet Ridge coalbed methane project in
Queensland, Australia for the quarter ended March 31, 1999, were $240,000 as
compared to $73,000 in the second quarter of fiscal 1998. Sales volumes
increased 129,000 Mcf, or 230%, to 185,000 Mcf from 56,000 Mcf in the
corresponding prior year's quarter, contributing $170,000 to increases in
revenue. The increase in sales volumes reflects production for a full three
months in the current year quarter, whereas in the prior year quarter, sales
from the Comet Ridge project did not commence until February 1998. The U.S.
dollar equivalent of gas prices received remained relatively flat decreasing 2%
to $1.30 per Mcf in the quarter ended March 31, 1999, from $1.32 per Mcf in the
quarter ended March 31, 1998, resulting in a slight decrease of $3,000 in
Australia revenues. Saltwater disposal and other income decreased $9,000 from
the corresponding quarter in the prior fiscal year.
Operating expenses decreased $73,000, or 6%, to $1,115,000 from $1,188,000
reported in the corresponding quarter in fiscal 1998. The Company's average
domestic lifting cost per BOE decreased 5% to $6.59 in the three months ended
March 31, 1999, from $6.94 in the prior year's three month period. These
decrease were primarily attributable to reduced operating expenses for shut in
wells and to a decrease in production taxes resulting from lower oil and gas
prices. A decrease of $170,000 in the Company's domestic operating expenses was
offset by an increase of $97,000 in Comet Ridge expenses in the current fiscal
quarter. The increase was the result of costs incurred for a full three months
of production in the quarter ended March 31, 1999, versus costs relating to only
a partial quarter's operating activity in the three months ended March 31, 1998.
The Company's average lifting cost for the Comet Ridge project was $5.74 per BOE
in the current fiscal quarter as compared to $8.68 per BOE in the prior year
quarter. Increased sales
10
in the current year quarter caused the lifting cost per BOE to decline from the
quarter ended March 31, 1998. Monthly operating and capital expenditures billed
for the Comet Ridge project have generally exceeded revenues from the project.
The Company has disputed certain charges, as discussed above, and believes that
operating expenses on a per-well basis can be reduced and is currently involved
in litigation with the operator concerning this and other matters. See Note 6
to the Consolidated Financial Statements herein.
General and administrative expenses increased by $113,000, or 25%, to $566,000
during the three months ended March 31, 1999, compared to $453,000 for the prior
year period. The increase was due to litigation costs associated with the Comet
Ridge coalbed methane project.
Depreciation, depletion and amortization ("DD&A") expense for the three months
ended March 31, 1999, decreased by $264,000, or 27%, to $720,000 from $984,000
reported for the comparable fiscal 1998 period. The decrease is attributable to
a lower DD&A rate per equivalent barrel resulting primarily from the write-down
of the full cost pool effective December 31, 1998. DD&A expense for the second
quarter of fiscal 1999 includes approximately $140,000 related to the Company's
Australia project as compared to total DD&A for Australia of $14,000 for the
three months ended March 31, 1998. The increase is due to increased production
volumes in the current fiscal quarter.
Interest income decreased $2,000, or 33%, to $4,000 in the quarter ended March
31, 1999, from $6,000 in the corresponding prior year quarter. This decrease is
due to a decrease in the average balance of cash and cash equivalents.
Interest expense for the three months ended March 31, 1999, increased $20,000,
or 6%, to $350,000 from $330,000 for the three months ended March 31, 1998, due
to an increase in long-term debt.
A foreign currency exchange loss of $4,000 was recognized during the quarter
ended March 31, 1999, related to revenue from the Comet Ridge project in
Queensland, Australia. There was no such gain or loss in the prior year period.
Net loss during the quarter ended March 31, 1999, excluded $35,000 attributable
to the minority interest held by Slough Estates USA Inc., in the Australian
subsidiary. The minority interest was acquired by Slough on December 22, 1998.
See Note 4 to the Consolidated Financial Statements herein.
RESULTS OF OPERATIONS - COMPARISON OF THE SIX MONTHS ENDED MARCH 31, 1999, AND
1998
The Company reported a net loss of $8,444,000 for the six months ended March 31,
1999, compared to a net loss of $999,000 for the six months ended March 31,
1998. Operating losses increased $7,278,000 to a loss of $7,748,000 in the
first six months of fiscal 1999 from a loss of $470,000 in the prior year
period. This increase was attributable primarily to the non-cash write-down of
domestic oil and gas assets in the amount of $5,727,000 in fiscal 1999 as well
as to lower oil and gas prices and a decrease in production volumes during the
first six months of fiscal 1999 as compared to the first half of fiscal 1998.
Following are detailed comparisons of the components of the respective
periods.
Operating revenues for the six months ended March 31, 1999, decreased
$1,451,000, or 30%, to $3,357,000 from $4,808,000 in the corresponding fiscal
1998 period. Oil volumes sold decreased 26,000 barrels, or 13%, to 182,000
barrels versus 208,000 barrels in the prior year period, decreasing revenue by
$431,000. Domestic gas volumes sold remained relatively flat increasing 13,000
Mcf, or 2%, to 663,000 Mcf in the current year period compared to 650,000 Mcf in
the six months ended March 31, 1998, resulting in a $24,000 increase in
revenues. The oil volume decrease was due to reduced production from wells on
which production was shut in or curtailed in response to low oil and gas prices
as well as to natural production declines that occur over the lives of
producing wells. Average oil prices decreased 38% to $10.26 per barrel for the
six months ended March 31, 1999, from $16.58 per barrel for the corresponding
prior year period, resulting in a $1,150,000 decrease in revenue. Prices
received by the Company for domestic gas sales decreased 21% to $1.45 per Mcf in
the current year period versus $1.84 in the prior year period, resulting in a
$259,000 revenue decrease. An increase in revenues of $390,000 was
attributable to sales from the Comet Ridge coalbed methane project in
Queensland, Australia, which generated revenues of $463,000 on sales of 366,000
Mcf of gas in the six months ended March 31, 1999, as compared to revenues of
$73,000 on sales of 56,000 Mcf in the prior fiscal year period. This increase
reflected six months of coalbed methane production recorded for the current
fiscal period, as opposed to approximately two months sales recorded for the
prior period, as gas sales did not commence until February 1998. A 5% decrease
in the average U.S. dollar equivalent gas price received to $1.26 per Mcf in the
current fiscal period from
11
$1.32 per Mcf in the prior fiscal year period was attributable to exchange rate
fluctuations. Saltwater disposal and other income decreased $25,000 from the
corresponding fiscal 1998 period.
Operating expenses related to the Company's domestic properties decreased
$484,000, or 20%, to $1,886,000 from $2,370,000 reported in the fiscal 1998
period. The Company's average lifting cost per equivalent barrel of domestic
production decreased 9% to $6.59 in the first six months of fiscal 1999 from
$7.25 in the prior year period. These decreases were attributable to reduced
operating costs related to shut in wells, and to a decrease in production taxes
resulting from lower oil and gas prices. The six month period ended March 31,
1999, included $374,000 of operating expenses attributable to the Comet Ridge
project in Australia, an increase of $293,000, or 362%, from $81,000 in the
prior year period. The increase relates to costs incurred for the full period
in the current fiscal year as opposed to only partial period expenses in the
prior year's fiscal period as discussed above. In addition, as discussed
above under results for the quarter, the Company is seeking to reduce
operating and capital expenditures billed by the operator. The increase in
sales volumes caused the Company's average lifting cost for the Comet Ridge
project to decrease to $6.12 per BOE during the six months ended March 31,
1999, from $8.68 per BOE in the prior year period.
General and administrative expenses increased $356,000, or 40%, to $1,238,000
during the six months ended March 31, 1999, compared to $882,000 for the prior
year period due primarily to an increase in legal fees attributable to the
Comet Ridge litigation. See Note 6 to the Consolidated Financial Statements
herein.
DD&A expense for the six months ended March 31, 1999, decreased $65,000, or 3%,
to $1,880,000 from $1,945,000 reported for the comparable fiscal 1998 period.
The decrease is attributable to a lower DD&A rate per equivalent barrel
resulting primarily from the write-down of the full cost pool as of December
31, 1998. In addition, DD&A expense for the six months ended March 31, 1999,
includes approximately $262,000 related to the Company's Australia project as
compared to $14,000 for the prior fiscal year-to-date. This increase relates
to increased production volumes from the Comet Ridge project in the current
fiscal year.
Interest income decreased $14,000, or 64%, to $8,000 in the six months ended
March 31, 1999, from $22,000 in the corresponding prior year period. This
decrease is due to a decrease in the average balance of cash and cash
equivalents.
Interest expense for the six months ended March 31, 1999, increased $213,000, or
39%, to $764,000 from $551,000 for the six months ended March 31, 1998. The
increase is attributable to an increase in long-term debt.
A foreign currency exchange gain of $22,000 was recognized during the six months
ended March 31, 1999, related to revenue from the Comet Ridge project in
Queensland, Australia. There was no such gain or loss in the prior year period.
Net loss during the six month fiscal period ended March 31, 1999, excluded
$38,000 attributable to the minority interest held by Slough in the Australian
subsidiary. The minority interest was acquired by Slough on December 22, 1998.
12
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
COMMODITY PRICE RISK
The Company's major market risk exposure is in pricing applicable to oil and gas
production. Prices realized for oil and gas sold can vary widely in response to
changing market conditions. Natural gas prices fluctuate based primarily on
weather patterns and regional supply and demand, while crude oil prices
fluctuate primarily upon worldwide supply and demand. In fiscal year ended
September 30, 1998, average monthly oil prices realized ranged from a low of
$11.37 per barrel to a high of $18.73 per barrel. In the six months ended March
31, 1999, average monthly per barrel oil prices ranged from a low of $8.18 to a
high of $13.17. With respect to domestic natural gas prices received during the
fiscal 1999 quarter, the average monthly price ranged from a low of $1.23 per
Mcf to a high of $1.87, while for fiscal year ended September 30, 1998, the
price received for domestic natural gas sales ranged from a low of $1.34 per
Mcf to a high of $2.04 per Mcf.
In an effort to mitigate the effects of price volatility, the Company typically
hedges a portion of its crude oil, and occasionally natural gas production
through several methods. In cases where direct investments are made in futures
contracts, gains or losses on the hedges are deferred and recognized in income
as the hedged commodity is produced. The Company has in recent years hedged
significant portions of its crude oil sales primarily through both "swap"
agreements and put options with financial institutions based upon prices quoted
by the New York Mercantile Exchange ("NYMEX"). Under swap agreements, the
Company receives a floor price but sometimes retains 50% of price increases
above the floor. Under put options, the Company has the right, but not the
obligation, to exercise the option and receive the strike price for the volume
of oil subject to the option. The Company received approximately $23,000 from
hedged oil production during the six months ended March 31, 1999. As of March
31, 1999, the Company had entered into swap contracts for the period April 1999
through July 1999 for total contract volumes of 50,000 barrels of oil at a
weighted average floor price of $15.12. The fair value of these hedging
contracts was approximately $(80,000) as of March 31, 1999.
INTEREST RATE RISK
The Company's risk associated with interest rate fluctuations relates to the
variable rate loans under its long-term debt that are benchmarked to LIBOR
interest rates. The outstanding bank debt at March 31, 1999, was $11,800,000
with interest payable at LIBOR plus 2.5%. The weighted average interest rate
for the six months ended March 31, 1999, was 7.44%. Interest on long-term
related party debt of $6,500,000 is payable at LIBOR plus 3.5%. The Company
has not entered into derivative financial instruments, such as interest rate
swaps, to hedge against fluctuations in interest rates because management
does not consider such risk to be significant.
13
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
- ------
See Note 6 to the Consolidated Financial Statements under Part I -
Item 1.
Item 2. Changes in Securities
- ------
None
Item 3. Defaults Upon Senior Securities
- ------
None
Item 4. Submission of Matters to a Vote of Security Holders
The Company held its Annual Meeting of Shareholders on January 26,
1999, and proxies for such meeting were solicited pursuant to
Regulation 14A adopted under the Securities Exchange Act of 1934.
There was no solicitation in opposition to management's nominees for
directors as listed in the proxy statement and all such nominees were
elected. The table below summarizes voting results:
Votes For Votes Withheld
---------- --------------
Kenneth L. Ancell 12,050,456 18,889
David L. Bradshaw 12,050,456 18,889
Eugene I. Davis 12,050,456 18,889
Douglas Kramer 12,049,431 19,914
Marshall D. Lees 12,050,456 18,889
In addition, the shareholders ratified the selection of
PricewaterhouseCoopers LLP as independent auditors. The vote was
12,040,049 for, 26,459 against and 2,837 abstained.
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.
See Note 5 to the Consolidated Financial Statements
under Part I - Item 1.
Filed in Part II
4.63 Promissory Note dated March 11, 1999, in the amount of
$6,500,000 issued by Registrant to Slough Estates USA
Inc., filed herewith.
4.64 Third Amendment of Subordination Agreement March 11,
1999, between Slough Estates USA Inc., and US Bank
National Association f/k/a Colorado National Bank,
filed herewith.
4.65 Amendment to Security Agreement dated March 11, 1999,
between Registrant and Slough Estates USA Inc., filed
herewith.
27 Financial Data Schedule.
(b) Reports on Form 8-K:
None
14
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: May 17, 1999 By: /s/ David L. Bradshaw
-----------------------------------
David L. Bradshaw, President, Chief
Executive Officer and Chairman of
the Board of Directors
Date: May 17, 1999 By: /s/ Lisa S. Wilson
-----------------------------------
Lisa S. Wilson, Chief Financial
Officer
15