<PAGE> 1
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, 1999
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
- --------- SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______________ to ____________
Commission file number 1-7796
TIPPERARY CORPORATION
(Exact name of registrant as specified in its charter)
Texas 75-1236955
(State or other jurisdiction of (I.R.S. employer
incorporation or organization) identification no.)
633 Seventeenth Street, Suite 1550
Denver, Colorado 80202
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (303) 293-9379
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, 1999, was $10,152,414.
Shares of the registrant's Common Stock outstanding as of December 1, 1999:
15,152,157 shares.
Documents incorporated by reference and the Part of the Form 10-K into which the
document is incorporated: Definitive Proxy Statement for the 2000 Annual Meeting
of Shareholders filed within 120 days after the fiscal year ended September 30,
1999 (Part III).
<PAGE> 2
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.
As of its year ended September 30, 1999, the Company's major areas of operations
were in Queensland, Australia, where it is involved in a coalbed methane
project, and the Permian Basin, the Rocky Mountain and Mid-Continent areas of
the United States. On November 22, 1999, the Company announced its plan to sell
its domestic oil and gas properties in connection with a $10,000,000 refinancing
(discussed in more detail below) and redirection of focus towards increasing
reserves and production of natural gas from coalbed methane properties. The
Company will seek to increase its coalbed methane gas reserves through
exploration and development projects and possibly through the acquisition of
producing properties.
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's 90%-owned Australian subsidiary, Tipperary Oil & Gas
(Australia) Pty Ltd, owns a 55.75% non-operating capital interest. The capital
expenditures in Australia during fiscal 1999 were approximately $5,650,000.
The Company and its co-venturers in the Comet Ridge coalbed methane project (the
"Group") own an Authority to Prospect ("ATP") granted by the Queensland
government covering approximately 1.1 million acres in the Bowen Basin. As of
September 30, 1999, the Group had drilled 29 wells on the project acreage, of
which 28 are in the area known as "Fairview," which is in the southern portion
of the ATP. The Company began selling gas from the Comet Ridge project during
February 1998 and was selling approximately 4,000 Mcf per day at year end. The
Company's strategy with respect to this project for the foreseeable future is to
participate with its co-venturers in drilling and connecting additional
development wells and conducting further exploration activities on the project
acreage. In addition, the Company will pursue exploration activities on acreage
it has recently acquired independently in the area of the Comet Ridge project.
This acreage currently consists of an ATP granted during fiscal 1999 covering
approximately 370,000 acres near the Comet Ridge project's ATP 526 and another
ATP covering approximately 850,000 acres in the vicinity, which the Company has
applied for and expects to be issued during December 1999.
The Company's domestic oil and gas operations were negatively impacted by the
severe worldwide decline in oil prices in fiscal 1998 and throughout much of
fiscal 1999. In addition to causing negative operating cash flows, these price
declines reduced the reported value of the Company's domestic oil and gas
properties and resulted in write-downs of the book value of the properties of
approximately $1,400,000 in fiscal 1998 and $5,700,000 in the first quarter of
fiscal 1999. In response to the decrease in cash flows, the Company curtailed
exploration projects and, to a lesser extent, development drilling projects in
the United States during fiscal 1999. Domestic capital expenditures of $698,000
during fiscal 1999 included development costs of $376,000, $289,000 of property
acquisition costs and $33,000 of exploration costs.
RECENT EVENTS
In November 1999, the Company entered into a refinancing agreement with Slough
Estates USA Inc. ("Slough"), the Company's largest (45.5%) shareholder. The
agreement provides that the Company will receive $10,000,000 ($1,000,000 of
which has already been advanced to the Company) in return for 6,329,114 shares
of newly-issued convertible preferred stock. Each share of preferred stock will
be convertible into one share of common stock at a conversion value of $1.58 per
common share. Proceeds from both the Slough financing and sale of domestic oil
and gas properties will be used to substantially reduce the Company's
outstanding debt, to fund ongoing coalbed methane exploration and development,
and for general corporate purposes. Upon closing the transaction with Slough,
the Company anticipates using $4,000,000 for an initial reduction of bank debt
from $11,800,000 to $7,800,000. Bank debt will be further reduced as proceeds
are received from property sales. The closing of the transaction with Slough is
scheduled to occur no later than December 31, 1999. See the discussion of
financing transactions with Slough in "Management's Discussion and Analysis of
Financial Condition and Results of Operations."
1
<PAGE> 3
MAJOR PRODUCING PROPERTIES
The following is a brief description of the Company's major producing areas:
AUSTRALIA
Bowen Basin. The Company, through its 90%-owned subsidiary, Tipperary Oil & Gas
(Australia) Pty Ltd, has a non-operating interest in the Comet Ridge coalbed
methane project in the Bowen Basin located in Queensland, Australia. The
project's ATP covers 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 Fairview area. The Group has applied for an additional ten
leases covering approximately 550,000 acres. Two of these additional lease
applications 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. The Company believes its share of the
remaining commitment through October 31, 2000 will not exceed US $700,000, at
current exchange rates.
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% and 42.66%
from the Fairview #1 through #20 wells and the Fairview #21 through #28 wells,
respectively, 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% from the Fairview #1 through #20 wells and 36.81%
from the Fairview #21 through #28 wells.
As of September 30, 1999, the Group had drilled 29 wells, of which 23 are
producing or capable of producing. Thus far, 11 of the wells have been connected
to a pipeline system. The Group is currently completing and connecting five
additional wells. Four of the five wells completed during fiscal 1999 were part
of an eight-well drilling program in the Fairview area that began during fiscal
1999. Two of the four wells were temporarily connected to the existing gathering
system and contributing to sales volumes by fiscal year-end. All eight wells
should be completed and permanently connected during fiscal 2000. During fiscal
1999, the Group also completed a well on a non-producing lease and incurred
expenditures toward the completion of a well on another non-producing lease in
order to satisfy minimum expenditure requirements for those leases.
UNITED STATES
The Company's domestic oil and gas assets which are being offered for sale
include producing properties in the Rocky Mountain region and in the Permian
Basin of West Texas and Southeast New Mexico. The Company operates 40 wells in
the Williston Basin of North Dakota and Montana of which 31 are active wells
accounting for 48% of the Company's daily oil production and 14% of its domestic
daily gas production volumes. Net production from the Powder River Basin in
northeastern Wyoming accounts for approximately 19% of the Company's daily oil
production. The Company owns non-operating interests in seven waterflood
projects in this area. The Company's current net daily production from the North
Bagley Field in the Permian Basin is distributed among 38 active wells operated
by the Company, and represents approximately 11% and 39%, respectively, of the
Company's total daily oil and gas domestic 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. The Company also has
reserves associated with undeveloped acreage as well as production from the West
Buna field in Jasper and Harding counties of east Texas. During fiscal 1999, net
oil and gas production from this field was approximately 5% and 13%,
respectively, of the Company's total domestic production volumes.
2
<PAGE> 4
PRODUCING WELLS AND ACREAGE
The following table sets forth information with respect to the Company's
producing wells and acreage as of September 30, 1999:
<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 2.01 -- -- 2,631 201 63,734 62,860
Montana 45 7.55 -- -- 9,928 1,660 23,715 7,857
Nebraska 8 1.70 -- -- 1,560 334 640 123
New Mexico 58 28.03 213 4.72 6,065 3,695 2,254 389
North Dakota 80 16.91 -- -- 17,081 3,605 83,767 26,724
Oklahoma 7 2.02 14 0.91 5,070 673 1,180 745
Texas 36 3.02 36 6.85 14,384 2,308 1,210 305
Wyoming 42 4.06 -- -- 15,129 1,368 22,672 6,339
Australia(2) -- -- 23 12.08 6,669 3,718 160,331 89,385
------- ------- ------- ------- ------- ------- ------- -------
Total 327 65.30 286 24.56 78,517 17,562 360,143 194,856
======= ======= ======= ======= ======= ======= ======= =======
</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 11 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, 1999, 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 23 producing wells and
an additional five wells pending completion and/or connection to a
gathering system are in the Fairview area in the southern portion of the
ATP. Eleven of the 23 wells are connected to a pipeline system. Two wells
are currently shut in and production from the remaining ten wells is being
flared at the wellhead during the de-watering process.
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. Part or all
of the above acreage may be sold in connection with the Company's planned
divestiture of its United States assets.
Substantially all of the Company's domestic oil and gas properties either have
been or may be pledged as security for bank debt. See Note 7 to the Company's
Consolidated Financial Statements.
3
<PAGE> 5
DRILLING ACTIVITIES
Information concerning the number of gross and net wells drilled by the Company
during fiscal 1999, 1998, and 1997 is as follows:
<TABLE>
<CAPTION>
United States Australia Total
------------------ ------------------ ------------------
Gross Net Gross Net Gross Net
------- ------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C>
September 30, 1999
Exploratory
Productive -- -- -- -- -- --
Dry -- -- -- -- -- --
Development
Productive 3 .01 5 2.79 8 2.80
Dry -- -- -- -- -- --
Total
Productive 3 .01 5 2.79 8 2.80
Dry -- -- -- -- -- --
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
</TABLE>
PRODUCTION
The Company's sales of net oil and gas production during fiscal 1999, 1998 and
1997 were 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>
1999 352,000 1,183,000 -- 904,000(1) 352,000 2,087,000
1998 426,000 1,320,000 -- 371,000(1) 426,000 1,691,000
1997 481,000 1,565,000 -- -- 481,000 1,565,000
</TABLE>
(1) Excludes the Company's share of total volumes produced but not sold.
Production of 462,000 Mcf during fiscal 1999 and 607,000 Mcf during fiscal
1998 was consumed in operations or flared at the wellhead from wells not
connected to the gathering system and in the de-watering process.
4
<PAGE> 6
AVERAGE PRICES AND AVERAGE LIFTING COSTS
The following table presents certain average price and lifting cost information
(all in U.S. dollars) for each of the years in the three-year period ended
September 30, 1999:
<TABLE>
<CAPTION>
Average price Price range
-------------------- ---------------------------------------------- Average lifting cost
Oil Gas Oil Gas per Equivalent
-------------------- -------------------- --------------------
(Bbl) (Mcf) High Low High Low Bbl Mcf
------- ------- ------- ------- ------- ------- ------- -------
United States:
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1999 $ 13.15 $ 1.68 $ 19.90 $ 8.18 $ 2.36 $ 1.23 $ 6.77 $ 1.13
1998 $ 14.63 $ 1.72 $ 18.73 $ 11.37 $ 2.04 $ 1.34 $ 6.73 $ 1.12
1997 $ 19.36 $ 2.22 $ 22.63 $ 14.70 $ 3.73 $ 1.68 $ 7.21 $ 1.20
------- ------- ------- ------- ------- ------- ------- -------
Australia:
1999 $ -- $ 1.32 $ -- $ -- $ 1.39 $ 1.21 $ -- $ .96
1998 $ -- $ 1.22 $ -- $ -- $ 1.32 $ 1.16 $ -- $ 1.28
1997 $ -- $ -- $ -- $ -- $ -- $ -- $ -- $ --
</TABLE>
The average lifting cost per Mcf for gas sales from the Comet Ridge project in
Queensland, Australia, has decreased with increasing sales volumes. The Company
believes that operating costs for this project can be reduced and is currently
involved in litigation with the operator of the project concerning this and
other matters. See Note 10 to the Consolidated Financial Statements herein.
MAJOR CUSTOMERS AND 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 have been 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. The Company had domestic sales in excess of 10% of
total U.S. revenues to three unaffiliated oil and gas customers during fiscal
1999 totaling 45%, three unaffiliated oil and gas customers during fiscal 1998
totaling 43%, and three unaffiliated oil and gas customers during fiscal 1997
totaling 41%. 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 impact on its ability to
sell its production to another purchaser at similar prices.
In Australia, the Company began selling gas under short-term gas contracts in
February 1998. In September 1998, the Company entered into a five-year,
fixed-price contract with ENERGEX Retail Pty Ltd (fka Allgas Energy Ltd) to
supply up to approximately 5,500 Mcf of gas per day beginning in January 1999.
If the Company is successful in selling all of its domestic oil and gas
properties during fiscal 2000, it is likely that all of the Company's product
sales will be under the contract with ENERGEX until such time as the Company
enters into new gas contracts.
PRICING
During fiscal 1999, approximately 70% 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 have been 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. In
order to guarantee a minimum weighted-average sales price and mitigate the
effects of price volatility, the Company has periodically hedged a portion of
its crude oil production through swap agreements with financial institutions and
direct contracts in the New
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<PAGE> 7
York Mercantile Exchange ("NYMEX"). Due to the anticipated sale of its domestic
oil and gas properties, the Company does not intend to hedge production beyond
March 2000. See the discussion of hedging activities in "Management's Discussion
and Analysis of Financial Condition and Results of Operations" and Note 1 to the
Company's Consolidated Financial Statements.
COMPETITION AND OTHER RISKS
As the Company seeks to redirect its focus toward production of natural gas from
coalbed methane properties, it will compete with a number of other potential
purchasers for coalbed methane properties, many of which have greater financial
and human resources than the Company. The ability of the Company to replace
reserves sold and produced will be dependent on the Company's ability to develop
its existing coalbed methane resources and/or select and acquire a sufficient
number of suitable coalbed methane properties.
This report contains certain statements of future business plans and objectives
and statements in Part I and 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 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 does not anticipate devoting any significant efforts or
expenditures on the projects during fiscal 2000. The Company will include the
Point Thomson Unit in Alaska among the United States properties offered for
sale.
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 1999, 1998 and
1997 is included in Note 11 to the Company's Consolidated Financial Statements
herein. In fiscal 1999, information concerning portions of the Company's
estimated proved oil and gas reserves was provided to the U.S. Department of
Energy.
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. Costs of approximately
$25,000 and $30,000 were incurred in fiscal 1999 and 1998, respectively, to
monitor environmental compliance issues.
6
<PAGE> 8
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 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 the year 2000. 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. In addition, the Company
leases office space at 950 Echo Lane, Suite 375, Houston, Texas 77024 and at
Level 5, 359 Queen Street, Brisbane, Queensland 4000, Australia.
EMPLOYEES
At September 30, 1999, the Company employed a total of 16 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 10 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, 1999.
7
<PAGE> 9
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, 1999, 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 1999 1998
------------- ----------------- ----------------
High Low High Low
----- ----- ----- -----
<S> <C> <C> <C> <C>
December 31 $2.13 $0.88 $6.63 $3.75
March 31 $1.88 $0.69 $4.63 $3.75
June 30 $1.94 $0.56 $4.25 $2.25
September 30 $1.63 $1.00 $3.00 $1.63
</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.
8
<PAGE> 10
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected financial data (in thousands, except per
share data) for each of the years in the five-year period ended September 30,
1999. This historical data may not be indicative of the Company's future
financial condition or results of operations, and should be read in conjunction
with the Consolidated Financial Statements and Notes thereto and "Management's
Discussion and Analysis of Financial Conditions and Results of Operations."
<TABLE>
<CAPTION>
1999 1998 1997 1996 1995
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Revenues $ 7,921 $ 9,082 $ 12,951 $ 11,136 $ 11,837
========== ========== ========== ========== ==========
Net income (loss) $ (9,295)(1) $ (6,398)(2) $ 472 $ (790) $ (1,284)
========== ========== ========== ========== ==========
Net income (loss) per common
share - basic and diluted $ (.63) $ (.49) $ .04 $ (.07) $ (.11)
========== ========== ========== ========== ==========
Weighted average shares
outstanding 14,689 13,118 13,050 11,807 11,190
========== ========== ========== ========== ==========
Total assets $ 48,005 $ 50,760 $ 54,995 $ 52,098 $ 47,044
========== ========== ========== ========== ==========
Total long-term debt $ 21,265 $ 19,200 $ 13,844 $ 13,994 $ 15,746
========== ========== ========== ========== ==========
Working capital $ 270 $ 1,045 $ 1,381 $ 4,011 $ 5,455
========== ========== ========== ========== ==========
Working capital provided (used)
by operations $ (515) $ 1,015 $ 5,201 $ 3,285 $ 3,917
========== ========== ========== ========== ==========
Stockholders' equity $ 23,452 $ 30,280 $ 36,488 $ 36,016 $ 29,818
========== ========== ========== ========== ==========
</TABLE>
- -----------
(1) Includes $5,727,000 write-down of oil and gas properties.
(2) Includes $1,399,000 write-down of oil and gas properties and $1,618,000
write-down of deferred tax asset.
9
<PAGE> 11
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, 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
Queensland, Australia and the United States. Approximately 70% of the Company's
capital expenditures have been applicable to the Comet Ridge coalbed methane
project and other investments in Australia. During the three fiscal years ended
September 30, 1999, the Company increased its interest in the Comet Ridge
coalbed methane project from 30% to 55.75%, participated in the drilling of
additional wells and began selling gas from the project during fiscal 1998.
These activities have resulted in estimated proved gas reserves of 131 Bcf as of
September 30, 1999. In the United States during this period, the Company used
its remaining available capital to acquire undeveloped leasehold acreage,
identify exploratory prospects and participate in exploratory and development
drilling and exploitation projects.
At September 30, 1999, estimates of total proved oil and gas reserves were
2,455,000 barrels and 141 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 estimated to be
$62,463,000. Proved oil and gas reserves in the United States increased by
67,000 barrels and 780 MMcf, respectively, from September 30, 1998 reserves
calculated using prices then in effect. These increases are attributable to
revisions of previous estimates of reserve volumes due to higher oil and gas
prices as of September 30, 1999, compared to September 30, 1998. The estimated
discounted (10%) future net cash flow from U.S. properties increased from
$16,176,000 as of September 30, 1998 (using prices as of that date) to
$22,308,000 as of September 30, 1999. This increase was also attributable to
higher oil and gas prices at September 30, 1999, compared to September 30, 1998.
Proved gas reserves in Australia increased 8.8 Bcf from September 30, 1998, as a
result of revisions of previous estimates due to the performance of the
producing wells.
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 December 31, 1998 oil and gas prices, the Company's full cost pool book
value exceeded this ceiling test value by $5,727,000. Accordingly, the book
value of oil and gas properties was written down by this amount as of December
31, 1998. See Note 5 to the Consolidated Financial Statements herein.
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RECENT DEVELOPMENT
In November 1999, the Company entered into a refinancing agreement with Slough
Estates USA Inc. ("Slough"), the Company's largest (45.5%) shareholder. The
agreement provides that the Company will receive $10,000,000 ($1,000,000 of
which has already been advanced to the Company) in return for 6,329,114 shares
of newly-issued convertible preferred stock. Each share of preferred stock will
be convertible into one share of common stock at a conversion value of $1.58 per
common share, which represents a premium of approximately 30% over the average
closing price of Tipperary common stock for the 20 trading days ended November
15, 1999. The closing is scheduled to occur no later than December 31, 1999.
Upon closing, Slough will convert approximately 3,000,000 shares of the
convertible preferred stock into common stock, with the remaining shares
convertible into common stock if shareholder approval is obtained to increase
the authorized shares of common stock from 20,000,000 shares to 50,000,000
shares.
The preferred stock will accrue cumulative dividends of 7.75% of the $1.58 face
value per share and will be payable semi-annually in arrears on June 30 and
December 31. The Company will have the option to make payment in kind with
restricted common stock based on the greater of the per share book value as set
forth in its most recent published financial statements or the average closing
market price of the common stock during the ten trading days preceding payment.
The preferred stock must be redeemed by the Company at the end of ten years, but
also is redeemable by the Company beginning five years after issuance of the
preferred stock. The redemption price will equal $1.58 per share plus
accumulated plus unpaid dividends.
The agreement also provides that Slough will receive warrants for 1,200,000
shares of restricted common stock at an exercise price of $2.00 per share. The
warrants may be exercised during an eight-year exercise period beginning two
years from the date of closing and ending 10 years from the date of closing. The
agreement with Slough contemplates the sale of the Company's domestic oil and
gas properties and is subject to an opinion from an independent financial
advisor that the contemplated transaction is fair, from a financial view, to the
Company's shareholders other than Slough.
Proceeds from the $10,000,000 Slough financing as well as proceeds from sale of
domestic oil and gas properties will be used to substantially reduce the
Company's outstanding debt, to fund ongoing coalbed methane exploration and
development, and for general corporate purposes. Upon closing the transaction
with Slough, the Company anticipates using $4,000,000 for an initial reduction
of bank debt from $11,800,000 to $7,800,000. Bank debt will be further reduced
as proceeds are received from property sales.
LIQUIDITY AND CAPITAL RESOURCES
For the three years ended September 30, 1999, 1998 and 1997 the Company's
primary sources of liquidity have been debt and equity financing, operating cash
flows, and sales of non-core producing properties and other assets. During this
three-year period, cash flows were used primarily for drilling operations, other
capital expenditures and the acquisition of additional interests in the Comet
Ridge project in Queensland, Australia. Remaining funds were invested in
domestic properties, including development drilling and exploration activities.
During fiscal 1999, proceeds of $10,872,000 from debt and equity financing
provided by Slough and cash on hand of $203,000 were used primarily to reduce
bank debt by $4,700,000 and fund capital expenditures of $6,179,000. The debt
and equity financing consisted of $4,000,000 from the issuance of 2,000,000
shares of restricted common stock, additional loans in the amount of $3,800,000
and $3,219,000 drawn on a loan commitment for $6,000,000 for development of the
Comet Ridge project. The Company paid equity financing costs of $147,000. See
Note 2 to the Consolidated Financial Statements herein.
During fiscal 1999, capital expenditures related to the Comet Ridge project in
Queensland, Australia totaled $5,649,000. Funds expended in connection with a
new eight-well drilling program in the Comet Ridge area totaled approximately
$2,225,000. As of September 30, 1999, four of the eight wells were completed and
had begun producing. Of the remaining expenditures in the Comet Ridge area,
approximately $900,000 was invested in inventory and gathering facilities. Two
additional wells were drilled at a cost of $790,000 net to the Company, one of
which was completed and producing as of September 30, 1999 while the other was
completed subsequent to the fiscal year end. Other capital expenditures totaling
$1,734,000 included costs associated with seismic data gathering and other
exploratory and development activities.
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The Authority to Prospect (ATP 526) granted by the Queensland government for the
Comet Ridge project has a remaining term through October 31, 2000, as well as a
work and expenditure requirement. The Company believes its share of the
remaining expenditure requirement will not exceed US $700,000 at current
exchange rates. 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%
from Fairview wells #1 through #20 and 42.66% from Fairview wells #21 through
#28, 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% and 36.81% from the Fairview #1 through #20 wells and the
Fairview #21 through #28 wells, respectively. The Company also has minimum
expenditure requirements related to ATP 655, which it was granted for a
four-year term beginning November 1, 1999. At current exchange rates, minimum
expenditures of approximately $64,000, $1,660,000, $1,530,000 and $1,020,000 are
required for annual periods ending October 31, 2000, 2001, 2002 and 2003. The
Company expects to be issued an additional exploration permit (ATP 675) by
December 31, 1999, which will also require minimum annual expenditures for the
term granted.
Capital expenditures related to domestic oil and gas operations totaled $698,000
during the year ended September 30, 1999. Additional interests in the Company's
operated wells were acquired for approximately $232,000 and $57,000 was expended
for non-producing leaseholds. Of the remaining capital expenditures,
approximately $135,000 was primarily attributable to recompletion activities.
The remaining costs related to various other minor capital expenditures for both
domestic oil and gas operations and corporate activities.
During fiscal 1998, the Company increased its bank debt by $2,656,000 and
secured additional loans from Slough in the amount of $400,000. Proceeds were
also generated by the sale of producing properties and stock issuances in the
amount of $1,456,000 and $190,000, respectively. These proceeds, along with
operating cash flows were used to fund capital expenditures of $8,033,000.
Approximately $4,950,000 was expended for the acquisition of an additional
interest in and funding further development of the Comet Ridge coalbed methane
project. The additional 5% interest in the project was acquired at a cost of
$3,200,000 and the remaining $1,750,000 was expended for gas gathering and
compression costs and other capital expenditures. Domestic capital expenditures
of $3,083,000 in fiscal 1998 included exploration and development costs of
$2,305,000, non-producing leasehold costs of $733,000 and other capital
expenditures of approximately $45,000.
During fiscal 1997, the Company obtained a loan of $2,300,000 from Slough and
used the proceeds 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. The
sales proceeds, along with cash on hand and cash flows from operating
activities, were used to retire $150,000 of bank debt, to 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.
The Company's bank credit agreement (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 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, 1999, and
September 30, 1998, was $11,800,000 and $16,500,000, respectively. The weighted
average interest rate was 7.89% as of September 30, 1999, and 8.48% as of
September 30, 1998. Upon expiration of the revolver (the "Conversion Date"), the
principal balance will convert to a three-year term loan. The Conversion Date
was recently extended by the bank from October 5, 1999, to October 5, 2000
subject to the bank receiving a payment of principal out of proceeds from the
anticipated transaction with Slough.
The majority of the Company's domestic oil and gas properties have been pledged
as security for the bank loan. 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
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the Company's assumptions. At September 30, 1999 and 1998, the borrowing base
was $11,800,000. 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. During fiscal 1999,
the Company used a portion of the proceeds obtained from the financing with
Slough to reduce the bank debt by $4,700,000 to the new borrowing base of
$11,800,000. At September 30, 1999, the borrowing base remained at $11,800,000,
but was being reviewed by the bank. Management expects that the anticipated
payment to the bank of $4,000,000 following the financing transaction and
subsequent payments from property sales proceeds will more than cover a
potential borrowing base deficiency. 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.
Outstanding loan balances due Slough at September 30, 1999 include a corporate
loan in the amount of $6,500,000 and a loan for $3,139,000 for the development
of the Company's Comet Ridge project. Interest is due quarterly on the $6.5
million note at the 90-day London Interbank Offered Rate plus 3.5%. The
weighted-average interest rate was 9.58% at September 30, 1999. The unpaid
principal balance of this note is due and payable March 11, 2002. During fiscal
1999, the Company received proceeds of $3,219,000 and made principal payments of
$80,000 on the $6,000,000 loan commitment from Slough for the eight-well
drilling program, leaving a balance due of $3,139,000 at September 30, 1999. The
unpaid principal balance of this loan bears interest at a rate of 10% per annum.
Principal and interest payments are due quarterly and must equal 75% of the cash
flow, as defined in the note, from the Comet Ridge properties. The Company has
also agreed to pay a finance charge of 7% of gross proceeds received from sales
from the Fairview #1 through #20 wells until the loan is repaid in full and an
additional payment of 7% of gross proceeds received from sales from the eight
new wells (Fairview #21 through #28) for the life of those wells. The unpaid
principal balance on the loan, together with accrued and unpaid interest and
finance charges, is due and payable five years from the date all proceeds are
received.
In order to provide a minimum weighted-average sales price and mitigate the
effects of price volatility, the Company periodically hedges a portion of its
crude oil production. The Company has in recent years hedged significant
portions of its crude oil 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 subject to the option. During
fiscal 1999 the Company hedged an average of 8,000 barrels per month
(approximately 27%) of its oil production. Net receipts (payments) pursuant to
the Company's hedging activities for fiscal 1999, 1998 and 1997 were ($200,000),
$507,000 and ($205,000), respectively.
As of September 30, 1999, the Company had in place swap agreements covering
15,000 barrels of oil per month for the months of October 1999 through March
2000 at a weighted-average floor price of $20.29 per barrel, with the Company
retaining 50% of price increases above the floor. None of the Company's gas
production is currently hedged for periods subsequent to September 30, 1999 and
the Company does not intend to enter into any further hedges of oil or gas
production beyond March 2000 due to the planned sale of the Company's domestic
oil and gas properties.
With the anticipated sale of the Company's domestic producing properties,
operating cash flow will decrease and the cash on hand from the sale of
preferred stock to Slough and subsequent proceeds from property sales will
provide cash for debt reduction and capital expenditures, and will be used to
fund general and administrative expenses. It is uncertain whether the Company
will be able to replace the cash flow from the domestic properties with new
coalbed methane properties in the United States in the near term, but cash flow
from the Comet Ridge project should increase considerably with the connection to
the gathering system of the new wells drilling during fiscal 1999. In addition,
the Company believes that the operating expenses and other costs charged by the
operator of the project should be reduced and is currently in litigation with
the operator concerning this and other matters. See Note 10 to the Consolidated
Financial Statements herein. The Company also expects to be involved in further
drilling programs on the Comet Ridge project and on its own ATP acreage, with
the goal of increasing cash flow from Australia.
The Company does not expect to pay significant income taxes in the near term in
either the United States or Australia due to its loss 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 $30 million as
of September 30, 1999, and expire over the period from fiscal 2000 through
fiscal
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2013. The Company has not generated taxable income in Australia and with its
loss carryforwards does not expect to generate taxable income in Australia in
the near term. The Company has recorded a $20.3 million asset for the future
benefit of its carryforwards and other tax benefits. As of September 30, 1999,
this asset was offset by a valuation allowance of approximately $18.8 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. See Note 9 to the
Consolidated Financial Statements herein.
Year 2000
The following information constitutes a "Year 2000 Readiness Disclosure" for
purposes of the Year 2000 Information and Readiness Disclosure Act.
The Year 2000 compliance issue 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
has evaluated and tested its computer information and communication systems for
Year 2000 readiness with the assistance of an outside consulting firm and
believes it has resolved all issues relating to reprogramming, replacing and
testing the affected computer systems for year 2000 compliance. The Company's
management information software applications have been modified and certified to
be Year 2000 compliant by its software vendor. An on-site testing program,
successfully completed in September 1999, found no instances of non-compliance.
The Company has also evaluated and upgraded its desktop computers, networks,
servers and software applications, as well as its non-information technology
systems, to assure Year 2000 compliance.
The Company has contacted significant suppliers, purchasers, financial
institutions, and other key business partners and has not been notified of any
material year 2000 problems. The Company cannot assure that there will not be
material adverse effects if these third parties have failed to convert their
systems in a timely manner, but believes the consequences would likely be
temporary. The Company does not believe that any contingency planning is
necessary for the potential non-compliance of third party vendors.
Compliance costs have not been material and future costs, if any, related to
Year 2000 are not expected to be material. Funding has been provided by
operating cash flows and expensed as incurred.
RESULTS OF OPERATIONS
Comparison of the Fiscal Years Ended September 30, 1999 and 1998
The Company reported a net loss of $9,295,000 in fiscal 1999 versus a net loss
of $6,398,000 in fiscal 1998. The 1999 loss included a $5,727,000 non-cash
write-down of domestic oil and gas properties, whereas the 1998 loss reflected
$1,399,000 and $1,618,000 non-cash write-downs of domestic properties and the
Company's deferred income tax asset, respectively, and a $422,000 write-down of
deferred financing costs. The loss without these write-downs increased $609,000
in fiscal 1999 over that of fiscal 1998. The gross profit from oil and gas sales
decreased $793,000 or 19% to $3,334,000 in fiscal 1999 from $4,127,000 in fiscal
1998. The decrease was due to lower domestic oil and gas volumes produced and
prices received for the year ended September 30, 1999 as compared to fiscal
1998.
Operating revenues for the year ended September 30, 1999, decreased $1,161,000,
or 13%, to $7,921,000 from $9,082,000 in fiscal 1998. Domestic revenues declined
$1,874,000, or 22%, from $8,494,000 in fiscal 1998 to $6,620,000 in the current
fiscal year. Oil volumes decreased 74,000 barrels, or 17%, to 352,000 barrels
versus 426,000 barrels in the prior year, decreasing revenues by $1,070,000.
Domestic gas volumes decreased 137,000 Mcf, or 10%, to 1,183,000 Mcf in the
current year compared to 1,320,000 Mcf in the prior fiscal year, resulting in a
$236,000 decrease in revenues. Reduced oil and gas volumes sold resulted from
naturally declining production rates and from production shut-in or curtailed in
response to low product prices seen throughout most of fiscal 1999. Average oil
prices decreased 10% to $13.15 per barrel for the year ended September 30, 1999,
from $14.63 per barrel for fiscal 1998, resulting in a $521,000 revenue
decrease. Prices received by the Company for domestic gas sales decreased 2% to
$1.68 per Mcf in fiscal 1999 from $1.72 in fiscal 1998 causing revenue decreases
of $47,000. Other domestic income, including saltwater disposal, decreased
$26,000 from the prior fiscal year.
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Significant increases in revenues from the Company's Australian holdings offset
some of the domestic revenue declines. An increase in revenues of $739,000 was
attributable to sales from the Comet Ridge coalbed methane project in
Queensland, Australia, which generated revenues of $1,191,000 in fiscal 1999 as
compared to revenues of $452,000 in fiscal 1998. Volumes sold increased 533,000
Mcf, or 144%, from 371,000 Mcf in fiscal 1998 to 904,000 Mcf in fiscal 1999,
contributing $650,000 to revenue increases. The U.S. dollar equivalent of gas
prices received increased 8% to $1.32 per Mcf in fiscal 1999 from $1.22 per Mcf
in fiscal 1998 resulting in an increase in revenues of $89,000. The revenue
increase from the Comet Ridge project was attributable to a full year of sales
in fiscal 1999 compared to eight months of sales in fiscal 1998, increasing
levels of volumes sold during fiscal 1999 and to a favorable increase in
exchange rates in fiscal 1999 compared to fiscal 1998.
Operating expenses for the year ended September 30, 1999 decreased $366,000, or
7%, to $4,587,000 for fiscal 1999 as compared to $4,953,000 in the prior fiscal
year. Operating expenses attributable to domestic properties decreased $760,000,
or 17%, to $3,717,000 in fiscal 1999 from $4,477,000 in fiscal 1998. The
decrease was attributable to reduced operating expenses for wells on which
production was shut in or curtailed. Reduced sales volumes in the current fiscal
year contributed to an increase of 1% in the average lifting costs per
equivalent barrel of production, to $6.77 in the current fiscal period from
$6.73 in the prior fiscal year.
Operating expenses attributable to the Company's Australian coalbed methane
project increased $394,000, or 83%, to $870,000 in fiscal 1999 as compared to
$476,000 in fiscal 1998. While the Company reported higher operating expenses,
the average lifting cost for the Comet Ridge project decreased 25%, to $.96 per
Mcf in the current fiscal year from $1.28 per Mcf in the fiscal 1998 due to
significantly increased sales volumes. Monthly operating and capital
expenditures billed for the Comet Ridge project have generally exceeded revenues
from this project. The Company has disputed certain charges and believes that
operating and capital expenditures should be substantially reduced. Since August
1998 the Company has been involved in litigation with the operator of the
project concerning this and other matters. See Note 10 to the Consolidated
Financial Statements herein.
General and administrative expenses increased $492,000, or 28%, to $2,262,000 in
fiscal 1999 from $1,770,000 in fiscal 1998, primarily due to litigation costs
associated with the Comet Ridge project. See Note 10 to the Consolidated
Financial Statements herein.
Depreciation, depletion and amortization ("DD&A") expense decreased $820,000, or
21%, to $3,154,000 in fiscal 1999 from $3,974,000 in fiscal 1998. The decrease
was attributable to a lower DD&A rate per equivalent barrel for domestic
production resulting from the write-down of the full cost pool effective
December 31, 1998. A longer economic reserve life based on increased product
prices also contributed to the rate decrease. Domestic DD&A expense reductions
were offset by increases related to the Company's Australian project. As a
result of increased sales from the Comet Ridge project, DD&A expense
attributable to the Australia full cost pool increased $276,000, or 107%, to
$533,000 in fiscal 1999 as compared to $257,000 in fiscal 1998.
Interest expense increased $279,000, or 21%, to $1,633,000 in fiscal 1999 from
$1,354,000 in fiscal 1998. The increase was primarily attributable to an
increase in debt and to higher interest rates. See Note 7 to the Consolidated
Financial Statements herein. Interest income decreased $18,000, or 58%, to
$13,000 in fiscal 1999 from $31,000 in fiscal 1998. The decrease was due to a
decrease in the average balance of cash and cash equivalents during fiscal 1999
as compared to fiscal 1998.
Foreign currency exchange gains of $19,000 in fiscal 1999 resulted from
favorable exchange rates applied to payments received in Australian currency for
coalbed methane gas sales from the Comet Ridge project. Losses of $21,000 were
recorded in the prior fiscal year.
No income tax benefit or expense was recognized in fiscal 1999. Income tax
expense of $1,618,000 for fiscal 1998 resulted from an increase in the deferred
tax asset valuation allowance. The increase in the valuation allowance was
attributable to a decrease in oil and gas prices during fiscal 1998.
The net loss during fiscal 1999 excluded $115,000 attributable to the minority
interest in the Australian subsidiary held by Slough. As discussed above under
Liquidity and Capital Resources, Slough acquired 10% of the stock in Tipperary
Oil & Gas (Australia) Pty Ltd., on December 22, 1998.
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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 were the result of sales of producing
properties during fiscal 1998 and to natural declines in production. The average
oil price decreased 24% to $14.63 in fiscal 1998 from $19.36 in fiscal 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 $1.28 per
Mcf, related to sales from the Comet Ridge project which commenced in February
1998.
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.
DD&A expense increased $442,000, or 13%, to $3,974,000 in fiscal 1998 from
$3,532,000 in fiscal 1997. The increase was 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 for fiscal 1998 also includes DD&A of the
Australia property not included in fiscal 1997 DD&A due to the commencement of
sales from the Comet Ridge project in February 1998.
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. 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.
Other income (expense) for the fiscal year ended September 30, 1998, included
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. 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.
16
<PAGE> 18
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.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Company's Consolidated Financial Statements and supplementary financial data
follow page 23 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, 1999, 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 23 and are incorporated
herein by reference.
(b) During the last quarter of the Company's fiscal year ended September 30,
1999, the Company filed no reports on Form 8-K.
(c) Exhibits:
For a list of exhibits, see "Exhibits" which follows page 18 and is
incorporated herein by reference.
17
<PAGE> 19
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 15, 1999 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 15, 1999
- -------------------------------- and Chairman of the Board of Directors
David L. Bradshaw
/s/ Lisa S. Wilson Chief Financial Officer and December 15, 1999
- -------------------------------- Principal Accounting Officer
Lisa S. Wilson
/s/ Kenneth L. Ancell Executive Vice President - Corporate December 15, 1999
- -------------------------------- Development and Director
Kenneth L. Ancell
/s/ Eugene I. Davis Director December 15, 1999
- --------------------------------
Eugene I. Davis
/s/ Douglas Kramer Director December 15, 1999
- --------------------------------
Douglas Kramer
/s/ Marshall D. Lees Director December 15, 1999
- --------------------------------
Marshall D. Lees
</TABLE>
18
<PAGE> 20
EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
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 Central Bank, N.A., filed as Exhibit 4.47 to Form 10-Q
dated March 31, 1996, and incorporated herein by reference.
</TABLE>
19
<PAGE> 21
EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
<S> <C>
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., and
incorporated herein by reference.
4.58 Promissory Note dated December 22, 1998, in the amount of
$5,500,000 issued by the Registrant to Slough Estates USA Inc.,
and incorporated herein by reference.
4.59 Loan Agreement Promissory Note dated December 22, 1998, in the
amount of $6,000,000 between Registrant and Slough Estates USA
Inc., and incorporated herein by reference.
4.60 Security Agreement dated December 22, 1998, between the
Registrant and Slough Estates USA Inc., and incorporated herein
by reference.
</TABLE>
20
<PAGE> 22
EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
<S> <C>
4.61 Pledge of Stock dated December 22, 1998, between the Registrant
and Slough Estates USA Inc., and incorporated herein by
reference.
4.62 Second Amendment of Subordination Agreement dated December 22,
1998, between Slough Estates USA Inc., and US Bank, N.A. f/k/a
Colorado National Bank, and incorporated herein by reference.
4.63 Promissory Note dated March 11, 1999, in the amount of
$6,500,000 issued by Registrant to Slough Estates USA Inc., and
incorporated herein by reference.
4.64 Third Amendment of Subordination Agreement dated March 11, 1999,
between Slough Estates USA Inc., and US Bank National
Association f/k/a Colorado National Bank, and incorporated
herein by reference.
4.65 Amendment to Security Agreement dated March 11, 1999, between
the Registrant and Slough Estates USA Inc., and incorporated
herein by reference.
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.
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.
</TABLE>
21
<PAGE> 23
EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
<S> <C>
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.
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.
10.58 Warrant to Purchase the Registrant's common stock dated December
22, 1998, issued to Slough Estates USA Inc., and incorporated
herein by reference.
10.59 Subscription Agreement to purchase Registrant's common stock
dated December 22, 1998, between Registrant and Slough Estates
USA Inc., and incorporated herein by reference.
</TABLE>
22
<PAGE> 24
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
<S> <C>
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, dated June 13, 1996, SEC File No. 333-40589, pages 5
through 8, and incorporated herein by reference.
</TABLE>
23
<PAGE> 25
TIPPERARY CORPORATION AND SUBSIDIARIES
Index to Consolidated Financial Statements
<TABLE>
<S> <C>
Report of Independent Accountants F-2
Consolidated Balance Sheet
September 30, 1999 and 1998 F-3
Consolidated Statement of Operations
Years ended September 30, 1999, 1998 and 1997 F-4
Consolidated Statement of Stockholders' Equity
Years ended September 30, 1999, 1998 and 1997 F-5
Consolidated Statement of Cash Flows
Years ended September 30, 1999, 1998 and 1997 F-6
Notes to Consolidated Financial Statements F-7
</TABLE>
F-1
<PAGE> 26
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, 1999 and 1998, and
the results of their operations and their cash flows for each of the three years
in the period ended September 30, 1999, 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 13, 1999
F-2
<PAGE> 27
TIPPERARY CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheet
September 30, 1999 and 1998
(in thousands)
<TABLE>
<CAPTION>
1999 1998
--------- ---------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents $ 430 $ 633
Receivables 1,525 1,408
Inventory 209 218
Other current assets 899 66
--------- ---------
Total current assets 3,063 2,325
--------- ---------
Property, plant and equipment, at cost:
Oil and gas properties, full cost method 136,562 136,647
Other property and equipment 2,402 2,571
--------- ---------
138,964 139,218
Less accumulated depreciation, depletion and amortization (95,642) (92,626)
--------- ---------
Property, plant and equipment, net 43,322 46,592
--------- ---------
Noncurrent portion of deferred income taxes, net 1,573 1,573
Other noncurrent assets 47 270
--------- ---------
$ 48,005 $ 50,760
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of note payable - related party $ 174 $ --
Accounts payable 1,780 680
Accrued liabilities 592 341
Production taxes payable 46 103
Royalties payable 201 156
--------- ---------
Total current liabilities 2,793 1,280
--------- ---------
Long-term debt 11,800 16,500
Long-term notes payable - related party 9,465 2,700
Commitments and contingencies (Note 10)
Minority interest 495 --
Stockholders' equity
Common stock; par value $.02; 20,000,000 shares
authorized; 15,161,755 issued and 15,152,157
outstanding in 1999; 13,161,755 issued and
13,133,955 outstanding in 1998 303 263
Capital in excess of par value 107,977 105,564
Accumulated deficit (84,803) (75,476)
Treasury stock, at cost; 9,598 shares in 1999;
27,800 shares in 1998 (25) (71)
--------- ---------
Total stockholders' equity 23,452 30,280
--------- ---------
$ 48,005 $ 50,760
========= =========
</TABLE>
See accompanying notes to consolidated financial statements.
F-3
<PAGE> 28
TIPPERARY CORPORATION AND SUBSIDIARIES
Consolidated Statement of Operations
Years ended September 30, 1999, 1998 and 1997
(in thousands, except per share data)
<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Revenues $ 7,921 $ 9,082 $ 12,951
Costs and expenses
Operating 4,587 4,953 5,505
General and administrative 2,262 1,770 1,503
Depreciation, depletion and amortization 3,154 3,974 3,532
Write-down of oil and gas properties 5,727 1,399 --
Write-down of deferred financing costs -- 422 --
Loss on sale of investment in
NGL fractionating plant -- -- 538
-------- -------- --------
Total costs and expenses 15,730 12,518 11,078
-------- -------- --------
Operating income (loss) (7,809) (3,436) 1,873
-------- -------- --------
Other income (expense):
Interest income 13 31 99
Interest expense (1,633) (1,354) (840)
Loss on disposition of stock -- -- (258)
Foreign currency exchange gain (loss) 19 (21) --
-------- -------- --------
Total other expense (1,601) (1,344) (999)
-------- -------- --------
Income (loss) before income taxes (9,410) (4,780) 874
-------- -------- --------
Current income tax expense -- -- (1)
Deferred income tax expense -- (1,618) --
-------- -------- --------
Income (loss) before equity in loss of
NGL fractionating plant and minority interest (9,410) (6,398) 873
Equity in loss of NGL fractionating plant -- -- (401)
Minority interest in loss of subsidiary 115 -- --
-------- -------- --------
Net income (loss) $ (9,295) $ (6,398) $ 472
======== ======== ========
Net income (loss) per share - basic and diluted $ (.63) $ (.49) $ .04
======== ======== ========
Weighted average shares outstanding 14,689 13,118 13,050
======== ======== ========
</TABLE>
See accompanying notes to consolidated financial statements.
F-4
<PAGE> 29
TIPPERARY CORPORATION AND SUBSIDIARIES
Consolidated Statement of Stockholders' Equity
Years ended September 30, 1999, 1998 and 1997
(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, 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
Net loss -- -- -- (9,295) -- -- (9,295)
Common stock and warrants
issued 2,000 40 2,413 -- -- -- 2,453
Treasury stock issued to
officers in lieu of
cash compensation 18 -- -- (32) (18) 46 14
------ -------- ---------- ----------- --- -------- --------
Balance September 30, 1999 15,152 $ 303 $ 107,977 $ (84,803) 10 $ (25) $ 23,452
====== ======== ========== =========== === ======== ========
</TABLE>
See accompanying notes to consolidated financial statements.
F-5
<PAGE> 30
TIPPERARY CORPORATION AND SUBSIDIARIES
Consolidated Statement of Cash Flows
Years ended September 30, 1999, 1998 and 1997
(in thousands)
<TABLE>
<CAPTION>
1999 1998 1997
------- ------- -------
<S> <C> <C> <C>
Cash flows from operating activities:
Net income (loss) $(9,295) $(6,398) $ 472
------- ------- -------
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation, depletion and amortization 3,154 3,974 3,532
Write-down of oil and gas properties 5,727 1,399 --
Write-down of deferred financing costs -- 422 --
Issuances of compensatory common stock 14 -- --
Minority interest (115) -- --
Loss on sale of investment in NGL fractionating plant -- -- 538
Equity in loss of NGL fractionating plant -- -- 401
Loss on disposition of stock -- -- 258
Deferred income tax expense -- 1,618 --
Change in assets and liabilities:
(Increase) decrease in receivables (117) 558 188
(Increase) decrease in inventory 9 (21) (7)
(Increase) decrease in other current assets (833) 57 --
Increase (decrease) in accounts payable
and accrued liabilities 1,351 (542) (191)
Increase (decrease) in advances from joint owners -- (468) 468
Increase (decrease) in royalties payable 45 (17) 25
Decrease in production taxes payable (57) (56) (27)
Other 1 (1) --
------- ------- -------
9,179 6,923 5,185
------- ------- -------
Net cash provided (used) by operating activities (116) 525 5,657
------- ------- -------
Cash flows from investing activities:
Proceeds from sale of assets 705 1,456 39
Proceeds from sale of common stock -- -- 638
Proceeds from sale of investment in NGL fractionating plant -- -- 1,800
Capital expenditures (6,179) (8,033) (9,435)
Investment in NGL fractionating plant -- -- (265)
------- ------- -------
Net cash used in investing activities (5,474) (6,577) (7,223)
------- ------- -------
Cash flows from financing activities:
Proceeds from borrowing 7,019 3,056 2,300
Principal repayments (4,780) -- (150)
Proceeds from issuance of stock 2,228 190 --
Proceeds from subsidiary sale of stock 610 -- --
Proceeds from issuance of warrants 310 -- --
Payments for debt and equity financing -- (90) (630)
------- ------- -------
Net cash provided by financing 5,387 3,156 1,520
------- ------- -------
Net decrease in cash and cash equivalents (203) (2,896) (46)
Cash and cash equivalents at beginning of year 633 3,529 3,575
------- ------- -------
Cash and cash equivalents at end of year $ 430 $ 633 $ 3,529
======= ======= =======
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest $ 1,393 $ 1,431 $ 831
Income taxes $ -- $ -- $ 1
</TABLE>
See accompanying notes to consolidated financial statements.
F-6
<PAGE> 31
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
September 30, 1999, 1998 and 1997
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.
Principles of Consolidation
The consolidated financial statements include the accounts of Tipperary
Corporation and its wholly-owned subsidiaries Tipperary Oil & Gas Corporation
and Burro Pipeline Corporation, and its 90%-owned subsidiary, Tipperary Oil &
Gas (Australia) Pty Ltd, and its proportionate share of assets, liabilities,
revenues and expenses of unincorporated joint ventures and partnerships. All
intercompany transactions and balances have been eliminated.
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.
F-7
<PAGE> 32
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
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 and the Company considers the risk of loss
to be minimal.
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, 1999 and 1998, 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 5 to the
Consolidated Financial Statements herein. 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 a portion of general and administrative
expenditures 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 1999 or 1998; however, the Company
capitalized $297,000 of interest costs in fiscal 1997.
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 twenty years.
F-8
<PAGE> 33
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
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.
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 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 1999, the Company hedged an average of
8,000 barrels per month (approximately 27%) of its oil production. Net receipts
(payments) pursuant to the Company's hedging activities for fiscal 1999, 1998
and 1997 were ($200,000), $507,000, and ($205,000), respectively.
As of September 30, 1999, the Company had in place swap agreements covering
15,000 barrels of oil production for each month for the months of October 1999
through March 2000 at a weighted-average floor price of $20.29 per barrel. None
of the Company's gas production is currently hedged for periods subsequent to
September 30, 1999, and the Company does not expect to enter into any new
contracts to hedge any oil or gas production beyond March in anticipation of
selling its domestic oil and gas properties. The exposure related to contracts
in effect as of September 30, 1999, was approximately $155,000. If and when
properties are sold prior to March 31, 1999, the Company will evaluate its
exposure and may terminate its swap agreements prior to maturity.
Earnings (Loss) Per Share
Basic earnings per share is computed based on 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.
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 have been incurred to obtain new financing.
These expenses, as they related 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> 34
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Significant Customers
The Company had domestic sales in excess of 10% of total revenues to three
unaffiliated oil and gas customers during fiscal 1999 totaling 45%, three
unaffiliated oil and gas customers during fiscal 1998 totaling 43%, and three
unaffiliated oil and gas customers during fiscal 1997 totaling 41%. All sales
from the Company's Comet Ridge project in Queensland, Australia, are currently
made to one purchaser under a five-year gas supply contract which commenced in
January 1999. 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. To the extent the Company is
successful in its efforts to sell all of its domestic oil and gas properties
during fiscal 2000, it is likely that all of the Company's sales will be under
the contract with ENERGEX until such time as the Company enters into new gas
contracts.
Segment Information
The Company has one business segment; oil and gas exploration, development and
production and operates in two geographic areas, the United States and
Australia. See Note 11 to the Consolidated Financial Statements herein.
Impact of New Accounting Pronouncements
In June 1998, the FASB issued Statement of Financial Accounting Standards No.
133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS
133"). This statement is effective for all fiscal quarters of fiscal years
beginning after June 15, 2000, and will be adopted by the Company effective
October 1, 2000. SFAS 133 requires companies to report the fair market value of
derivatives on the balance sheet and record in income or other comprehensive
income, as appropriate, any changes in the fair value of the derivative. The
Company does not believe that adoption of SFAS 133 will have a material impact,
if any, on its financial statements.
NOTE 2 - RELATED PARTY TRANSACTIONS
On December 22, 1998, the Company closed a transaction involving debt and equity
financing of $11,700,000 provided by Slough Estates USA Inc. ("Slough"), the
Company's largest shareholder. This financing was comprised of a loan commitment
for $6,000,000 to be used for development of the Comet Ridge project in
Queensland, Australia; $4,000,000 from the issuance of 2,000,000 shares of
restricted common stock and asset sales; and an additional loan in the amount of
$1,700,000.
The commitment for the $6,000,000 loan was made to the Company's Australian
subsidiary. As of September 30, 1999, $3,219,000 had been advanced against this
note, the proceeds of which are being used to fund an eight-well drilling
program and gas gathering system expansion. The loan is evidenced by a five-year
note bearing interest at the rate of 10% per annum. The terms of the note also
provide that Slough will receive additional payments based upon a contractual
payment right to 7% of gross revenues from both the existing and eight proposed
wells until the loan is paid in full, after which it will be reduced to 7% of
gross revenues from only the eight new wells for the life of those wells.
The shares of the Company's common stock were issued to Slough at a premium over
the market value on the date of closing. Of the $4,000,000 received by the
Company, $2,228,000 was recorded as proceeds from the issuance of common stock,
net of equity financing costs of $147,000, and the premium of $1,625,000 was
recorded as proceeds attributable to other assets acquired by Slough in the
transaction. Approximately $705,000 of the premium was allocated to the value of
the contractual payment right and was treated as a sale of a portion of the
Company's share of reserves in the Comet Ridge project. In accordance with the
requirements of the full cost method of accounting, the Australian full cost
pool was reduced by this amount. In connection with this transaction, the
Company issued to Slough ten percent of the common stock of the Australian
subsidiary and a warrant to purchase up to 500,000 shares of the Company's
common stock at $3.00 per share, exercisable during a five-year period beginning
in December 2000 and ending in December 2005. The remainder of the premium was
assigned to the warrant and to the common stock of the subsidiary in the amounts
of $310,000 and $610,000, respectively.
F-10
<PAGE> 35
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
The loan of $1,700,000 was consolidated with previous loans from Slough into a
total note payable of $5,500,000 as of December 31, 1998. The $1,700,000
proceeds from this loan and the $4,000,000 proceeds from the issuance of common
stock and sale of assets were used to reduce the Company's bank debt by
$4,700,000 which reduced the loan balance due the bank to $11,800,000. The
remaining $1,000,000 of the proceeds from the financing was retained by the
Company for working capital and minor capital expenditures. On March 11, 1999,
the Company borrowed from Slough an additional $1,000,000 and combined this loan
and its then existing $5,500,000 loan from Slough into a new three-year note for
$6,500,000. The loan agreement provides for interest to be paid quarterly at the
London Interbank Offered Rate plus 3.5%.
NOTE 3 - SUBSEQUENT EVENTS
On November 19, 1999 the Company and Slough entered into a letter agreement
regarding additional financing to be provided by Slough. At a closing
contemplated to be held in December 1999, Slough agreed to purchase 6,329,114
newly-issued shares of the Company's preferred stock for total consideration of
$10 million, or $1.58 per share. The purchase price per share represented
approximately 130% of the average closing price of the Company's common stock
for the 20 trading days ended November 15, 1999. Also, at the closing, the
Company will issue to Slough warrants for 1,200,000 shares of common stock at an
exercise price of $2.00 per share. The warrants may be exercised during an
eight-year period beginning two years from the date of the closing and ending 10
years from the date of closing. The preferred stock will accrue cumulative
dividends of 7.75% of the face value per share ($1.58) per year payable
semi-annually in arrears, on June 30 and December 31. Dividends on the preferred
stock may be payable in common stock at the option of the Company based on the
greater of the per share book value as set forth in its most recent published
financial statements or the average closing market price of the common stock
during the preceding 10 trading days.
The preferred stock plus accumulated but unpaid dividends will be convertible
into common stock at any time after issuance at the option of the holder and
prior to maturity or earlier redemption. Each share of preferred stock will be
convertible into one share of common stock. In addition, at the closing of the
transaction, Slough will convert approximately 3,000,000 shares of convertible
preferred stock into approximately 3,000,000 shares of common stock. The number
of shares of common stock issuable upon conversion of the preferred stock will
be subject to customary anti-dilution provisions. Accumulated but unpaid
dividends will be converted into common stock based on the greater of the per
share book value as set forth in the Company's most recent published financial
statements or the average closing market price of the common stock during the
preceding 10 trading days. The preferred stock will be callable or redeemable by
the Company at face amount plus accumulated but unpaid dividends, five years
after issuance of the preferred stock, with mandatory redemption 10 years after
issuance at this price. The preferred stock will be subordinated to all existing
and future debt. The preferred stock will have no voting rights, other than as a
class as provided by Texas law. The Company intends to use $4,000,000 of
proceeds from this financing to reduce bank debt and the remaining proceeds for
general corporate purposes.
The above transaction was approved by the non-interested directors of the Board
of the Company on November 18, 1999, but is subject to receipt by the
non-interested members of the Board of Directors of an opinion from an
independent financial adviser that the above transactions are fair, from a
financial view, to the shareholders of the Company other than Slough. In
connection with the transaction, the Company agreed to employ best efforts,
including the retention of Hanifen, Imhoff Inc., an investment banking firm, to
market and sell substantially all of its domestic oil and gas assets. The
proceeds from the asset sales will be dedicated to the repayment of senior debt
(anticipated to be $7.8 million) and then to repay the existing $6.5 million
promissory note to Slough discussed above.
NOTE 4 - MINORITY INTEREST IN SUBSIDIARY
Effective December 22, 1998, the Company issued to Slough ten percent of the
common stock of its Australian subsidiary in accordance with the terms of the
previously described debt and equity financing transaction. See Note 2 to the
Consolidated Financial Statements herein. The resulting non-Company owned
shareholder interest has been accounted for as a minority interest in the
accompanying Consolidated Financial Statements.
F-11
<PAGE> 36
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
NOTE 5 - OIL AND GAS FULL COST POOLS
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, 1999, the
capitalized cost applicable to the Australia full cost pool was $27,679,000. All
capitalized costs are subject to depletion and depreciation.
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, 1999, was $15,061,000.
Included in this total are $2,122,000 of acquisition costs attributable to
nonproducing oil and gas leases, primarily in the Williston Basin, that have
been excluded from depletable costs pending further evaluation.
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
December 31, 1998, oil and gas prices, the Company recognized a non-cash
impairment of its domestic oil and gas properties in the amount of $5,727,000
pursuant to the ceiling limitation.
See Note 11 (unaudited) for supplementary information on oil and gas operations,
including capitalized costs, costs incurred, results of operations and estimated
reserves for the Company's Australia and United States properties.
NOTE 6 - 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,
---------------------------------------
1999 1998 1997
---------- ---------- ---------
<S> <C> <C> <C>
Numerator:
Net income (loss) $ (9,295) $ (6,398) $ 472
Denominator:
Weighted-average shares outstanding 14,689 13,118 13,050
Effect of dilutive securities:
Assumed conversion of dilutive options -- -- 216
---------- --------- ---------
Weighted-average shares and dilutive potential
common shares 14,689 13,118 13,266
Basic earnings (loss) per share $ (0.63) $ (0.49) $ 0.04
========= ========= =========
Diluted earnings (loss) per share $ (0.63) $ (0.49) $ 0.04
========= ========= =========
</TABLE>
Potentially dilutive common stock of 145,000 shares from the exercise of options
and warrants was antidilutive for fiscal 1998. There were no potentially
dilutive shares in fiscal 1999.
F-12
<PAGE> 37
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
NOTE 7 - 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,
1999, and September 30, 1998, was $11,800,000 and $16,500,000, respectively. The
weighted average interest rate was 7.89% as of September 30, 1999 and 8.48% as
of September 30, 1998. Upon expiration of the revolver (the "Conversion Date"),
the principal balance will convert to a three-year term loan. The Conversion
Date was recently extended by the bank from October 5, 1999 to October 5, 2000
subject to the bank receiving a payment of principal out of proceeds from the
anticipated transaction with Slough.
The majority of the Company's domestic oil and gas properties have been pledged
as security for the bank loan. 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, 1999 and 1998, the borrowing base
was $11,800,000. 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. At September 30, 1999,
the borrowing base remained at $11,800,000, but was being reviewed by the bank.
Management expects that the anticipated payment to the bank of $4,000,000
following the financing transaction and subsequent payments from property sales
proceeds will more than cover a potential borrowing base deficiency. 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 2001 through 2004.
Related party debt at September 30, 1999 include loans from Slough, the
Company's 45.5% shareholder. Included are a corporate loan in the amount of
$6,500,000 and $3,139,000 for the development of the company's Comet Ridge
project. Interest is due quarterly on the $6.5 million note at the 90-day London
Interbank Offered Rate plus 3.5%. The weighted-average interest rate was 9.58%
at September 30, 1999. The unpaid principal balance of this note is due and
payable March 11, 2002. During fiscal 1999, the Company received proceeds of
$3,219,000 and made principal payments of $80,000 on the $6,000,000 loan
commitment from Slough for an eight-well drilling program, leaving a balance due
of $3,139,000 at September 30, 1999. The unpaid principal balance bears interest
at a rate of 10% per annum. Principal and interest payments are due quarterly
and must equal 75% of the cash flow, as defined in the note, from the Comet
Ridge properties. The Company has also agreed to pay a finance charge of 7% of
gross proceeds received from sales from the Fairview #1 through #20 wells until
the loan is repaid in full and an additional payment of 7% of gross proceeds
received from sales from the eight new wells (Fairview #21 through #28) for the
life of those wells. The unpaid principal balance on the loan, together with
accrued and unpaid interest and finance charges is due and payable five years
from the date all proceeds are received.
F-13
<PAGE> 38
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
NOTE 8 - STOCKHOLDERS' EQUITY
Stockholders' equity at September 30, 1999, and 1998 consisted of the following
(in thousands, except number of shares):
<TABLE>
<CAPTION>
1999 1998
--------- ---------
<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; 15,161,755 issued and 15,152,157 outstanding
as of September 30, 1999; 13,161,755 issued and
13,133,955 outstanding in 1998 303 263
Capital in excess of par value 107,977 105,564
Accumulated deficit (84,803) (75,476)
Treasury stock, at cost; 9,598 shares in 1999;
27,800 shares in 1998 (25) (71)
--------- ---------
Total stockholders' equity $ 23,452 $ 30,280
========= =========
</TABLE>
Common Stock Issuances
During fiscal 1999, the Company issued 2,000,000 shares of its common stock to
Slough Estates USA Inc., the Company's largest shareholder in connection with
the debt and equity financing transaction dated December 22, 1998. See Note 2 to
the Consolidated Financial Statements herein. The Company also issued 18,202
common shares from its treasury stock to certain of its officers in lieu of cash
compensation.
Stock Incentive Plans
In 1987, the Company adopted the 1987 Employee Stock Option Plan (the "1987
Plan") that provided for grants 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 the par value of the restricted stock issued. During fiscal 1999, the
Company issued options to acquire 134,000 shares of its common stock under this
plan.
F-14
<PAGE> 39
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
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, 1999:
<TABLE>
<CAPTION>
Weighted-Average
1987 Plan 1997 Plan Exercise Price
--------- --------- ----------------
<S> <C> <C> <C>
As of September 30, 1996 266,650 -- $ 3.75
Granted in fiscal 1997 85,000 37,500 $ 3.90
Forfeited in fiscal 1997 -- -- --
Exercised in fiscal 1997 -- -- --
------- -------
As of September 30, 1997 351,650 37,500 $ 3.80
------- -------
Granted in fiscal 1998 -- 81,000 $ 4.26
Forfeited in fiscal 1998 (51,666) (17,000) $ 4.37
Exercised in fiscal 1998 (30,584) -- $ 3.27
------- -------
As of September 30, 1998 269,400 101,500 $ 3.84
------- -------
Granted in fiscal 1999 -- 134,000 $ 2.24
Forfeited in fiscal 1999 -- (12,000) $ 2.81
Exercised in fiscal 1999 -- -- --
------- -------
As of September 30, 1999 269,400 223,500 $ 3.43
======= =======
Exercisable as of September 30, 1999 247,733 133,003 $ 3.16
======= =======
</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, 1999, are as follows:
<TABLE>
<CAPTION>
Weighted-Average
Shares Exercise Price
--------- ----------------
<S> <C> <C>
As of September 30, 1996 405,000 $ 2.70
Granted in fiscal 1997 105,000 $ 4.25
Expired in fiscal 1997 -- --
Exercised in fiscal 1997 -- --
---------
As of September 30, 1997 510,000 $ 3.02
---------
Granted in fiscal 1998 16,664 $ 3.63
Expired in fiscal 1998 -- --
Exercised in fiscal 1998 (53,100) $ 2.00
---------
As of September 30, 1998 473,564 $ 3.16
Granted in fiscal 1999 796,872 $ 2.52
Expired in fiscal 1999 -- --
Exercised in fiscal 1999 -- --
---------
As of September 30, 1999 1,270,436 $ 2.75
=========
Exercisable as of September 30, 1999 460,437 $ 3.10
=========
</TABLE>
F-15
<PAGE> 40
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
The following table summarizes information about stock options and warrants
outstanding at September 30, 1999:
<TABLE>
<CAPTION>
Options and Warrants Options and Warrants
Outstanding Exercisable
----------------------------------------------------- -------------------------------
Number Weighted Weighted Average Number Weighted
Range of Outstanding Average Remaining Exercisable Average
Exercise Prices at 9/30/99 Exercise Price Contractual Life at 9/30/99 Exercise Price
--------------- ----------- -------------- ----------------- ----------- --------------
<S> <C> <C> <C> <C> <C>
$1.50 to $2.00 511,900 $1.72 10.00 201,900 $2.00
$2.50 to $3.69 860,936 $2.99 6.36 339,269 $2.94
$4.00 to $5.13 390,500 $4.44 8.53 300,004 $4.49
$1.50 to $5.13 1,763,336 $2.94 7.90 841,173 $3.26
</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 fixed stock option grant 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 1999, 1998 and 1997 of $292,000, $130,000 and $431,000,
respectively, were estimated using the Black-Scholes option-pricing model with
the following weighted-average assumptions:
<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Expected life (in years) 8.00 5.00 6.00
Expected volatility 63.91% 66.16% 67.71%
Risk-free interest rate 5.30% 5.84% 6.20%
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>
<CAPTION>
1999 1998 1997
------------- ------------- ----------
<S> <C> <C> <C>
Net income (loss) As Reported $ (9,295,000) $ (6,398,000) $ 472,000
Pro forma $ (9,465,000) $ (6,599,000) $ 327,000
Income (loss) per share As Reported $ (.63) $ (.49) $ .04
Pro forma $ (.64) $ (.50) $ .03
</TABLE>
NOTE 9 - INCOME TAXES
Under Statement of Financial Accounting Standards No. 109, "Accounting for
Income Taxes," the Company has recorded a $20.3 million asset for the future
benefit of its net operating tax loss carryforwards and other tax benefits. As
of September 30, 1999, this asset was offset by a valuation allowance of
approximately $18.8 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
F-16
<PAGE> 41
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
appropriate. During fiscal 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 a recent history of net operating
tax losses, and the expiration within three years 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.
As of September 30, 1999, projections of future taxable income increased from a
year earlier due to a significant increase in oil and gas prices. In addition,
the Company expects to realize taxable gains from property sales during fiscal
2000 and plans to reduce debt substantially. With these factors in mind,
management determined that it is more likely than not that the current net
deferred tax asset will be realized and that no increase in the valuation
allowance was required. The $736,000 decrease in the valuation allowance during
the fiscal year ended September 30, 1999 was primarily attributable to the
expiration of a net operating loss carryover during fiscal 1999.
The net deferred tax asset is comprised of the following at September 30, 1999
and 1998:
<TABLE>
<CAPTION>
1999 1998
-------- --------
<S> <C> <C>
Deferred tax assets:
Federal and state net operating loss carryforwards $ 13,032 $ 15,112
Statutory depletion carryforwards 2,465 2,409
Property, plant and equipment 4,566 3,098
Tax credit carryforwards 260 372
Capital loss carryforward -- 68
Other 3 3
-------- --------
Gross deferred tax assets 20,326 21,062
-------- --------
Valuation allowance (18,753) (19,489)
-------- --------
Net deferred tax asset $ 1,573 $ 1,573
======== ========
</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>
<CAPTION>
1999 1998 1997
------- ------- -------
<S> <C> <C> <C>
Expected amount $(3,266) $(1,673) $ 165
Increase (decrease) from:
Increase (decrease) in valuation allowance (736) 1,237 (724)
Adjustments to and expiration of carryforwards 3,997 2,059 1,127
Permanent differences between financial
statement income and taxable income 5 (5) (568)
State taxes, net of federal benefit, and other -- -- 1
------- ------- -------
Total income tax expense (benefit) $ -- $ 1,618 $ 1
======= ======= =======
</TABLE>
F-17
<PAGE> 42
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
The Company has approximate net operating loss and investment tax credit
carryfowards (in thousands) available at September 30, 1999, as follows:
<TABLE>
<CAPTION>
Expiration Year Net Operating Loss Investment Tax Credit
--------------- ------------------ ---------------------
<S> <C> <C>
2000 $ 13,701 $ 31
2001 4,817 14
2003 991 --
2004 3,360 --
2009 1,391 --
2011 1,126 --
2012 1,563 --
2013 3,157 --
--------- ---------
Total $ 30,106 $ 45
========= =========
</TABLE>
The Company also has statutory depletion carryforwards of approximately
$7,043,000 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, 1999, no such ownership change had occurred.
NOTE 10 - COMMITMENTS AND CONTINGENCIES
The Company is plaintiff in a lawsuit filed on August 6, 1998, styled Tipperary
Corporation and Tipperary Oil & Gas (Australia) Pty Ltd v. Tri-Star Petroleum
Company, Cause No. CV42,265, in the District Court of Midland County, Texas. The
complaint, which concerns the Comet Ridge coalbed methane project in Queensland,
Australia, alleges that Tri-Star Petroleum Company ("Tri-Star"), operator of the
project, has failed to perform its duties under the operating agreement, and
seeks the removal of Tri-Star as operator, an accounting of expenses charged to
the joint interest account and unspecified amounts for damages for breach of
contract. Among the allegations in the complaint are that Tri-Star has refused
to allow the Company to inspect the books and records of the project, has
attempted to block the Company's right to take its proportionate share of gas
production in kind, may have improperly billed expenses to the joint interest
owners and has an impermissible conflict of interest precluding it from acting
as a reasonable and prudent operator. Tri-Star has answered the complaint
denying the claims and has asserted counterclaims against the Company for breach
of the operating agreement and mediation agreement between the parties and
interference with prospective contracts and business relations. Tri-Star filed a
counterclaim seeking monetary damages, but has not pleaded for any specific sum.
Two additional non-operating joint owners have intervened in the action as
plaintiffs, asserting a claim for the removal of Tri-Star as operator, and other
claims similar to those asserted by the Company. Discovery is in process.
On March 14, 1997, the Company filed a complaint along with several other
plaintiffs in BTA Oil Producers, et al. v. MDU Resources Group, Inc., et al. in
Stark County Court in the Southwest Judicial District of North Dakota. The
plaintiffs are suing the defendants for breach of gas sales contracts, unjust
enrichment, implied trust and related business torts. The case concerns the sale
by plaintiffs and certain predecessors of natural gas processed at the McKenzie
Gas Processing Plant in North Dakota to Koch Hydrocarbons Company. It also
concerns the contracts for resale of that gas to MDU Resources Group, Inc. and
Williston Basin Interstate Pipeline Company. The defendants have answered the
complaint denying the claims, and discovery is in process.
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 expiring
August 31, 2001. During the remaining term of the lease, the base rent is
payable in the amounts: $166,000 in fiscal 2000 and $152,000 in fiscal 2001,
plus expense recovery amounts. The Company paid rent for its Denver office of
approximately $133,000 in fiscal 1999 and $116,000 in each of fiscal 1998 and
1997. During fiscal 1999, the Company leased office space in Brisbane,
Queensland, Australia, on a month-to-month basis and paid total rent of
approximately US $11,000 for the year ended September 30, 1999. The Company has
also leased approximately 1,400 square feet of
F-18
<PAGE> 43
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
office space in Houston, Texas. The term of the lease commenced November 1,
1999, and terminates on March 31, 2001, with no rent payable for November 1999,
a base rent of $775 for the month of December 1999 and $1,715 each month
thereafter.
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-19
<PAGE> 44
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
NOTE 11 - 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 1999, 1998 and 1997 (in thousands) are
as follows:
CAPITALIZED COSTS:
<TABLE>
<CAPTION>
United States Australia Total
------------- ------------- -----------
<S> <C> <C> <C>
September 30, 1999:
Proved oil and gas properties $ 100,587 $ 27,972 $ 128,559
Unproved oil and gas properties 7,686 317 8,003
------------- ------------- -----------
108,273 28,289 136,562
Less accumulated depletion (93,212) (610) (93,822)
------------- ------------- -----------
Net capitalized costs $ 15,061 $ 27,679 $ 42,740
============= ============= ===========
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
============= ============= ===========
</TABLE>
COSTS INCURRED:
<TABLE>
<CAPTION>
United States Australia Total
------------- ------------- -----------
<S> <C> <C> <C>
September 30, 1999:
Property acquisition costs:
Proved oil and gas properties $ 232 $ 13 $ 245
Unproved oil and gas properties 57 15 72
------------- ------------- -----------
289 28 317
------------- ------------- -----------
Exploration costs 33 302 335
Development costs 376 5,319 5,695
------------- ------------- -----------
Total costs incurred $ 698 $ 5,649 $ 6,347
============= ============= ===========
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
============= ============= ===========
</TABLE>
F-20
<PAGE> 45
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
COSTS INCURRED (Continued):
<TABLE>
<CAPTION>
United States Australia Total
------------- ------------- -----------
<S> <C> <C> <C>
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>
Depletion rates per equivalent barrel of domestic production for the years ended
September 30, 1999, 1998 and 1997 were $4.51, $5.50 and $4.51, respectively.
Costs of $2,122,000, $3,608,000 and $3,417,000 related to domestic unproved oil
and gas properties which have not yet been evaluated were excluded from
depletable costs in fiscal 1999, fiscal 1998 and fiscal 1997, respectively. The
rate of depletion per equivalent barrel of production in Australia was $1.82 for
the year ended September 30, 1999, and $1.20 for the prior fiscal year. Costs of
$317,000 related to Australia properties which have not yet been evaluated have
been excluded from depletable costs in fiscal 1999.
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, 1999, (in thousands) are as follows:
<TABLE>
<CAPTION>
United States Australia Total
------------- ----------- -----------
<S> <C> <C> <C>
September 30, 1999:
Revenue from sale of oil and gas $ 6,620 $ 1,191 $ 7,811
Production costs (3,846) (870) (4,716)
Depreciation, depletion and amortization
including impairment (8,203) (415) (8,618)
Income tax expense -- -- --
------------- ----------- -----------
Operating income from petroleum
producing activities $ (5,429) $ (94) $ (5,523)
============= =========== ===========
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)
============= =========== ===========
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
============= =========== ===========
</TABLE>
Revenues of $110,000, $136,000 and $160,000 were not included above for 1999,
1998 and 1997, respectively, which
F-21
<PAGE> 46
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
represent revenues received primarily for saltwater disposal. Production costs
of $144,000 were included above for each of 1999, 1998 and 1997, which represent
costs paid or payable to other affiliates in the consolidated group. Costs
associated with the saltwater disposal revenue and other costs of $15,000,
$134,000 and $150,000 were not included above for 1999, 1998 and 1997,
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, 1999:
Total proved reserves:
Beginning of year 2,388 9,023 -- 122,509 2,388 131,532
Revisions of previous estimates 346 1,879 -- 10,130 346 12,009
Extensions, discoveries
and other additions 26 46 -- -- 26 46
Purchases of reserves in place 47 38 -- -- 47 38
Sale of reserves in place -- -- -- -- -- --
Production (352) (1,183) -- (1,366) (352) (2,549)
----- ------ ------- ------- ----- -------
End of year 2,455 9,803 -- 131,273(1) 2,455 141,076
===== ====== ======= ======= ===== =======
Proved developed reserves:
Beginning of year 2,114 7,255 -- 28,100 2,114 35,355
===== ====== ======= ======= ===== =======
End of year 2,171 8,003 -- 30,899(1) 2,171 38,902
===== ====== ======= ======= ===== =======
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
===== ====== ======= ======= ===== =======
</TABLE>
(1) Includes 13,127 MMcf of total proved reserves and 3,090 MMcf of proved
developed reserves attributable to the 10% minority interest held by Slough
Estates USA Inc., in Tipperary Oil & Gas (Australia) Pty Ltd. See Note 2.
F-22
<PAGE> 47
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, 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>
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 1999, 1998 and 1997 (in
thousands) follows:
<TABLE>
<CAPTION>
United States Australia Total
-------------- ------------- -------------
<S> <C> <C> <C>
September 30, 1999:
Future revenues $ 78,534 $ 177,744 $ 256,278
Future production costs (35,079) (33,032) (68,111)
Future development costs (1,490) (13,054) (14,544)
Future income tax expense (5,362) (39,575) (44,937)
------------- ------------- -------------
Future net cash flow 36,603 92,083 128,686
10% annual discount (14,295) (51,928) (66,223)
------------- ------------- -------------
Discounted future net cash flows $ 22,308 $ 40,155(1) $ 62,463
============= ============= =============
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
============= ============= =============
</TABLE>
(1) Includes approximately $4,016,000 attributable to the 10% minority
interest held by Slough Estates USA Inc., in Tipperary Oil & Gas
(Australia) Pty Ltd. See Note 2.
F-23
<PAGE> 48
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, 1999 (in
thousands) are as follows:
<TABLE>
<CAPTION>
United States Australia Total
-------------- ------------- -------------
<S> <C> <C> <C>
September 30, 1999:
Beginning of year $ 16,176 $ 30,680 $ 46,856
Oil and gas sales, net of production costs (2,897) (321) (3,218)
Net change in prices and production costs 7,179 3,466 10,645
Extensions and discoveries, less related costs 192 -- 192
Purchases of reserves in place, net 341 -- 341
Sale of reserves in place -- -- --
Change in estimated development costs 67 2,121 2,188
Revision of previous quantity estimates 2,743 2,533 5,276
Accretion of discount 1,618 3,068 4,686
Net change in income taxes (2,239) (1,590) (3,829)
Changes in production rates and other (872) 198 (674)
-------------- ------------- -------------
End of year $ 22,308 $ 40,155(1) $ 62,463
============== ============= =============
</TABLE>
At September 30, 1999, average oil and gas prices used in the determination of
future cash flows for domestic reserves were $22.08 per barrel and $2.48 per
Mcf, respectively. The average gas price used in the determination of future
cash flows for Australia reserves as U.S. $1.35 per Mcf.
(1) Includes approximately $4,016,000 attributable to the 10% minority interest
held by Slough Estates USA Inc., in Tipperary Oil & Gas (Australia) Pty Ltd. See
Note 2.
<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.
F-24
<PAGE> 49
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
<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 as $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.
F-25
<PAGE> 50
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
NOTE 12 - QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
The following is a summary of the unaudited quarterly results of operations for
the fiscal years ended September 30, 1999 and 1998 (in thousands, except per
share data):
<TABLE>
<CAPTION>
Quarter Ended
---------------------------------------------------------
December 31, March 31, June 30, September 30,
1998 1999 1999 1999 Total
------------ --------- -------- ------------- ---------
<S> <C> <C> <C> <C> <C>
Fiscal 1999
- -----------
Revenues $ 1,749 $ 1,608 $ 2,063 $ 2,501 $ 7,921
============ ========= ======== ============= =========
Gross profit $ 604 $ 493 $ 896 $ 1,341 $ 3,334
============ ========= ======== ============= =========
Net loss $ (7,336)(1) $ (1,108) $ (578) $ (273) $ (9,295)
============ ========= ======== ============= =========
Net loss per common
share - basic and diluted $ (.55) $ (.07) $ (.04) $ (.02) $ (.63)
============ ========= ======== ============= =========
</TABLE>
<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 loss $ (294) $ (705) $ (3,750)(2) $ (1,649) $ (6,398)
============ ========= ======== ============= =========
Net loss per common
share - basic and diluted $ (.02) $ (.05) $ (.29) $ (.13) $ (.49)
============ ========= ======== ============= =========
</TABLE>
(1) Includes $5,727,000 write-down of oil and gas properties.
(2) Includes $1,399,000 write-down of oil and gas properties and $1,618,000
write-down of deferred tax asset.
F-26
<PAGE> 51
EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
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 Central Bank, N.A., filed as Exhibit 4.47 to Form 10-Q
dated March 31, 1996, and incorporated herein by reference.
</TABLE>
<PAGE> 52
EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
<S> <C>
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., and
incorporated herein by reference.
4.58 Promissory Note dated December 22, 1998, in the amount of
$5,500,000 issued by the Registrant to Slough Estates USA Inc.,
and incorporated herein by reference.
4.59 Loan Agreement Promissory Note dated December 22, 1998, in the
amount of $6,000,000 between Registrant and Slough Estates USA
Inc., and incorporated herein by reference.
4.60 Security Agreement dated December 22, 1998, between the
Registrant and Slough Estates USA Inc., and incorporated herein
by reference.
</TABLE>
<PAGE> 53
EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
<S> <C>
4.61 Pledge of Stock dated December 22, 1998, between the Registrant
and Slough Estates USA Inc., and incorporated herein by
reference.
4.62 Second Amendment of Subordination Agreement dated December 22,
1998, between Slough Estates USA Inc., and US Bank, N.A. f/k/a
Colorado National Bank, and incorporated herein by reference.
4.63 Promissory Note dated March 11, 1999, in the amount of
$6,500,000 issued by Registrant to Slough Estates USA Inc., and
incorporated herein by reference.
4.64 Third Amendment of Subordination Agreement dated March 11, 1999,
between Slough Estates USA Inc., and US Bank National
Association f/k/a Colorado National Bank, and incorporated
herein by reference.
4.65 Amendment to Security Agreement dated March 11, 1999, between
the Registrant and Slough Estates USA Inc., and incorporated
herein by reference.
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.
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.
</TABLE>
<PAGE> 54
EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
<S> <C>
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.
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.
10.58 Warrant to Purchase the Registrant's common stock dated December
22, 1998, issued to Slough Estates USA Inc., and incorporated
herein by reference.
10.59 Subscription Agreement to purchase Registrant's common stock
dated December 22, 1998, between Registrant and Slough Estates
USA Inc., and incorporated herein by reference.
</TABLE>
<PAGE> 55
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
<S> <C>
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, dated June 13, 1996, SEC File No. 333-40589, pages 5
through 8, and incorporated herein by reference.
</TABLE>
<PAGE> 1
EXHIBIT 11.1
Calculation of Per Share Earnings
See Note 6 to the Consolidated Financial Statements herein.
<PAGE> 1
EXHIBIT 21.1
TIPPERARY CORPORATION AND SUBSIDIARIES
<TABLE>
<CAPTION>
Corporation State or Other Jurisdiction of Incorporation
----------- --------------------------------------------
<S> <C>
Tipperary Corporation Texas
Tipperary Oil & Gas Corporation Texas
Tipperary Oil & Gas (Australia) Pty Ltd Queensland, Australia
Burro Pipeline Corporation New Mexico
</TABLE>
<PAGE> 1
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference of our report dated
December 13, 1999, relating to the financial statements, which appears in this
Form 10-K, in the following:
1. Registration Statement on Form S-8 (No. 333-40589) of Tipperary
Corporation with respect to Common Stock Issued Pursuant to the 1995
Compensatory Warrant.
2. Prospectus constituting part of the Registration Statement on Form S-3
(No. 333-5653) of Tipperary Corporation with respect to Common Stock
Issued to the Heartland Small Cap Contrarian Fund and The Acorn Fund.
3. Registration Statement on Form S-8 (No. 33-61017) of the Tipperary
Corporation with respect to Common Stock Issued Pursuant to the 1987
Employee Stock Option Plan.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Denver, Colorado
December 13, 1999
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED BALANCE SHEET AND STATEMENT OF OPERATIONS FOUND ON PAGES F-3 AND
F-4 OF THE COMPANY'S FORM 10-K FOR THE YEAR ENDED SEPTEMBER 30, 1999, 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-30-1999
<PERIOD-START> OCT-01-1998
<PERIOD-END> SEP-30-1999
<CASH> 430
<SECURITIES> 0
<RECEIVABLES> 1,525
<ALLOWANCES> 0
<INVENTORY> 209
<CURRENT-ASSETS> 3,063
<PP&E> 138,964
<DEPRECIATION> 95,642
<TOTAL-ASSETS> 48,005
<CURRENT-LIABILITIES> 2,793
<BONDS> 21,265
0
0
<COMMON> 303
<OTHER-SE> 23,149
<TOTAL-LIABILITY-AND-EQUITY> 48,005
<SALES> 7,921
<TOTAL-REVENUES> 7,921
<CGS> 4,587
<TOTAL-COSTS> 15,730
<OTHER-EXPENSES> (32)
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 1,633
<INCOME-PRETAX> (9,295)
<INCOME-TAX> 0
<INCOME-CONTINUING> (9,295)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (9,295)
<EPS-BASIC> (.63)
<EPS-DILUTED> (.63)
</TABLE>
