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