<PAGE>
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, 1995
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:
<TABLE>
<CAPTION>
Title of each class Name of each exchange on which registered
------------------- -----------------------------------------
<S> <C>
Common Stock, $.02 par value American Stock Exchange
</TABLE>
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, 1995 was $28,347,000.
Shares of the registrant's Common Stock outstanding as of December 1, 1995:
11,209,604 shares.
Documents incorporated by reference and the Part of the Form 10-K into which
the document is incorporated: Definitive Proxy Statement for the 1996 Annual
Meeting of Shareholders filed within 120 days after the fiscal year ended
September 30, 1995 (Part III).
<PAGE>
PART I
ITEM 1. BUSINESS
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, and its executive offices are located at 633 Seventeenth Street, Suite
1550, Denver, Colorado 80202 (telephone number 303-293-9379). The Company
was previously involved in gas transmission and gas processing, but disposed
of its gas transmission assets during fiscal 1993 and its gas processing
assets during fiscal 1990.
During its fiscal years ended September 30, 1991, 1992 and 1993, the
Company's efforts were focused primarily on the acquisition and exploitation
of producing oil and gas properties in the United States. The Company's
basic strategy was to increase oil and gas reserves by purchasing existing
proved reserves from other oil and gas companies. Where feasible, the
Company sought to acquire producing properties with additional unproved
reserves which could be established through implementation of various
exploitation techniques and through further development. The Company's
strategy was based largely upon the shift in investment emphasis of major and
large independent oil and gas companies to international areas, accompanied
by the divestiture of many of their domestic properties. These factors,
among others, created opportunities for oil and gas entities such as the
Company to acquire producing properties. During the fiscal year ended
September 30, 1994, the number of property dispositions by such integrated
companies in the Company's target size and price range decreased
significantly, and competition to purchase available properties intensified.
During this same time period, the Company's exploratory and development
activity increased to offset capital expenditures which had been originally
budgeted for property acquisitions. Although the Company continues to review
opportunities for the acquisition of producing properties periodically, its
current emphasis on exploration and development activity may continue
assuming a continuing shortage of properties offered for sale and higher
price levels. The Company's primary areas of oil and gas production are the
Rocky Mountains, Permian Basin and southeast Texas regions of the United
States.
During fiscal 1992, the Company acquired a 30% nonoperating interest in the
Comet Ridge project for the purpose of exploring for coalbed methane gas on a
1,365,000 acre concession in Queensland, Australia. The Company and its
co-venturers (the "Group") began initial drilling operations in Australia on
adjacent farmout acreage in November 1993, with the first well being
noncommercial. During the fiscal year ended September 30, 1994, two
additional wells were drilled on the Group's original Authority to Prospect
("ATP"), and during the fiscal year ended September 30, 1995, 14 additional
wells were drilled on the ATP. During the fiscal year ended September 30,
1995, 14 of the wells, located in the Fairview area of the southern portion
of the ATP, were completed and began production testing. While the Group has
not entered into a gas sales contract, initial production has been necessary
to gather data relating to gas and water production and estimated reserves in
place. Gas reserve quantities have now been estimated by independent
petroleum engineers, although proved reserves cannot be assigned to the
properties until a market is established for the gas, and sales prices and
delivery costs are known. In August 1995, the operator of this property
initiated litigation against the Company and one other participant alleging
that the two parties have forfeited their interest in the project except for
their interest in existing wells; see Note 8 to the Company's Consolidated
Financial Statements.
Also during fiscal 1995, the Company acquired an undivided 87.5% interest in
approximately 9,000 additional leasehold acres in its Montana
three-dimensional ("3-D") seismic project area and completed a 3-D seismic
survey covering approximately 30% of the total 45,000 acres. Several
prospects were identified by the survey, and the Company has staked well
locations to test two of these. While discussions are underway with
potential drilling partners, the Company may retain its full 87.5% interest
if suitable terms are not offered by third parties.
During the fiscal year ended September 30, 1994, the Company entered into a
joint venture which has constructed a natural gas liquids (NGL) fractionating
plant in Alabama. The Company committed to contribute $1,148,000 in cash, in
return for a 45% interest in plant profits prior to payout of its investment
and a 27% interest thereafter. The Company agreed to increase its investment
in the plant during fiscal 1995, in connection with a restructuring of the
plant ownership following certain cost overruns and construction delays. As
of September 30, 1995, the Company had invested $1,454,000, which investment
had increased to $1,939,000 subsequent to year end. Subsequent to the
restructuring, the Company expects to own an interest in the Plant of between
50% and 55% prior to payout and an
1
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interest of between 37% and 47% thereafter. The Plant commenced testing
operations in November 1995 and is expected to commence full production prior
to calendar year end. See Note 4 to the Company's Consolidated Financial
Statements.
The Company sold its interest in certain gas properties and related assets in
La Plata County, Colorado for approximately $4,500,000 on May 1, 1995 and
sold its interest in other oil and gas properties in southern Louisiana for
approximately $600,000 on February 24, 1995. The two property sales involved
nonoperating working interests and represented approximately 5.4% of the
Company's total discounted future net revenues and 486,000 barrels of oil
equivalent ("BOE"), or 7.7% of the Company's total proved reserve volumes as
of September 30, 1994. Under the full cost method of accounting, no gain or
loss was recognized on the property sales; the proceeds were credited to the
full cost pool, thereby reducing the book value of the Company's oil and gas
properties.
In addition to these primary business activities, the Company owns rights to
an interest in a prospect-generating joint venture in mainland China; an oil
spill cleanup technology on which a patent application is pending; a royalty
interest in an Australian bauxite deposit; and a discovered but undeveloped
oil and gas property in Alaska. None of these assets currently generate
revenues and management anticipates the Company will not be devoting any
significant efforts or expenditures on these projects during fiscal 1996.
The Company is effectively controlled by related entities, SDK Incorporated
("SDK") and Texland Oil, Inc. ("Texland"). Double-Double Partners II
("Double-Double"), an investment partnership related to both SDK and Texland,
became a 49% shareholder as a result of a financial restructuring of the
Company in 1986. Subsequent to this restructuring, Texland made loans to the
Company in connection with the Company's further efforts to reduce and
restructure long-term debt. In January 1990, both Double-Double and Texland
exchanged certain debt for common stock, after which the related group owned
68% of the Company's common stock. On July 8, 1993, both the Company and
Double-Double sold common stock in a public offering which resulted in a
decrease in the related group's ownership from 66.7% to 44.3%. As of
September 30, 1994, the related group owned 43.8% of the Company's
outstanding common stock. During fiscal 1995, Double-Double was liquidated,
with SDK receiving 1,564,835 shares of common stock previously held by
Double-Double, and James A. McAuley, a director of the Company, receiving
218,453 shares of common stock. As of September 30, 1995, the related group
owned approximately 41.8% of the Company's outstanding common stock.
OIL AND GAS EXPLORATION AND PRODUCTION
GENERAL. The Company entered the oil and gas business in 1969 when it
acquired 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 of coalbed methane gas. During its fiscal years ended September
30, 1991, 1992 and 1993, the Company focused primarily on the acquisition and
exploitation of producing oil and gas properties, but also began
participating in an increasing amount of drilling. During the fiscal years
ended September 30, 1994 and 1995, the Company's capital expenditures were
primarily directed to exploration and development, due to both a decrease in
the availability of producing properties offered for sale at prices
acceptable to the Company and the Company's commencement of significant
activity on domestic and international exploratory and development projects
discussed herein. In conducting its oil and gas activities, the Company
continues to periodically review privately offered property acquisition
opportunities as well as those available through competitive bid from major
oil companies and other independent oil and gas companies.
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DRILLING ACTIVITIES. Information concerning the number of gross and net
wells drilled by the Company during fiscal 1995, 1994 and 1993 is as follows:
<TABLE>
<CAPTION>
1995 1994 1993
-------------- --------------- --------------
GROSS NET GROSS NET GROSS NET
----- ---- ----- ----- ----- ----
<S> <C> <C> <C> <C> <C> <C>
Exploratory
United States
Productive 2 .21 - - - -
Dry 6 1.37 - - 1 0.25
Australia
Productive 1(1) .30(1) 2(1) 0.60(1) - -
Dry - - 1 0.30 - -
Development
United States
Productive 10 .91 13 1.41 5 1.03
Dry - - 1 0.06 - -
Australia
Productive 13(1) 3.90(1) - - - -
Dry - - - - - -
Total
Productive 26 5.32 15 2.01 5 1.03
Dry 6 1.37 2 0.36 1 0.25
</TABLE>
(1) Fourteen of the wells have been completed and are currently in the
de-watering phase, and two in remote areas are awaiting further
completion and testing procedures. Gas production has reached commercial
levels on several wells, and continued de-watering is expected to further
increase production rates. Gas reserve quantities for the existing wells
have been estimated by independent petroleum engineers, although proved
reserves cannot be assigned to the properties until a market is
established for the gas, and sales price and delivery costs are known.
OIL AND GAS PRODUCTION. The Company's net oil and gas production for fiscal
1995, 1994 and 1993 is as follows:
<TABLE>
<CAPTION>
OIL GAS
(BBL) (MCF)
------- ---------
<S> <C> <C>
1995 565,000 2,061,000
1994 646,000 2,500,000
1993 379,000 1,367,000
</TABLE>
The following table presents certain price and average lifting cost
information for each of the years in the three-year period ended September
30, 1995:
<TABLE>
<CAPTION>
Average price Price range
---------------- ------------------------------------ Average lifting
Oil Gas Oil Gas cost per
(Bbl) (MCF) High Low High Low equivalent Bbl
------ ----- ------ ------ ----- ----- --------------
<S> <C> <C> <C> <C> <C> <C> <C>
1995 $15.43 $1.43 $17.70 $12.23 $1.64 $1.14 $6.14
1994 $14.70 $1.65 $16.02 $13.03 $1.74 $1.51 $5.70
1993 $17.62 $1.81 $19.15 $16.00 $2.20 $1.51 $6.28
</TABLE>
3
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SALES CONTRACTS. The Company sells its oil and gas production to numerous
purchasers, generally under short-term contracts. While certain gas sales
are dedicated to gas processing plants for longer terms, a substantial
portion of residue gas and plant liquids are typically sold by the plants on
a short-term basis. Since numerous purchasers compete to purchase both oil
and gas from the Company's properties, the Company does not believe that the
loss of any single existing purchaser would have a material adverse effect on
its financial condition or results of operations. The Company is not
obligated to provide a fixed and determinable quantity of oil or gas in the
future under existing contracts and agreements.
PRICING. During fiscal 1995, approximately 75% of the Company's oil and gas
revenues were attributable to crude oil sales. Both oil and natural gas
prices are subject to significant fluctuations; natural gas based primarily
upon weather patterns and regional supply and demand and crude oil based
primarily on worldwide supply and demand. The majority of the Company's gas
sales are through "percentage of proceeds" contracts with gas processing
plant owners, whereby the Company receives various percentages of both
residue gas and plant liquids sales proceeds. Residue gas sold under these
contracts may be sold at "spot" prices or longer term contract prices by the
respective gas processing plant owner. The Company has in recent years
hedged significant portions of its crude oil and gas sales through both
"swap" agreements with financial institutions and direct contracts in the New
York Mercantile Exchange ("NYMEX"). Under these agreements, the Company
usually receives a "floor" price but retains a significant percentage of
price increases above the "floor." During fiscal 1995, the Company hedged an
average of 14,167 barrels per month (approximately 30%) of its oil
production. Payments made by the Company pursuant to these hedges totaled
approximately $183,000, or $0.32 per barrel of total oil production.
Subsequent to September 30, 1995, the Company entered into swap agreements
covering 10,000 barrels of oil per month from December 1, 1995 through
September 30, 1996. These agreements provide for the Company to receive an
average floor price based on the NYMEX West Texas Intermediate quote of
$16.15 per barrel plus 50% of increases above $16.15. The Company's average
price received at the wellhead during fiscal 1995 was approximately $2.53 per
barrel less than the NYMEX average. None of the Company's gas production was
hedged during fiscal 1995, or as of September 30, 1995, but it may be hedged
in the future.
SUMMARY OF PRESENT ACTIVITIES. See Item 2. "Oil and Gas Properties -
Exploratory Operations" for information concerning the Company's present
domestic and international drilling activities. Subsequent to September 30,
1995, the Company elected to participate for its pro rata interest in the
drilling of three nonoperated wells in North Dakota, New Mexico and Oklahoma.
Management continues to review the economics of the Company's oil and gas
properties, taking certain corrective actions when necessary, including
plugging wells deemed permanently impaired or depleted, terminating oil and
gas leases deemed uneconomic and selling properties when justified by
comparative opportunities.
COMPETITION. During the fiscal year ended September 30, 1995, the number of
smaller producing property packages offered for sale continued at low levels
and many of the Company's competitors shifted their emphasis to exploratory
and development drilling. This has caused increased competition for
leasehold acreage in certain areas and may cause increased competition in
other areas where the Company is presently acquiring acreage. Further, many
of the companies which compete with the Company for available leasehold
acreage are substantially larger and may have greater financial resources.
Notwithstanding such competition, the Company believes that its current
leasehold position, in combination with leasing in new areas currently being
pursued, will provide an adequate inventory of prospects for the exploratory
activity the Company expects to carry on for the next two to three years.
DISCONTINUED OPERATIONS
The Company conducted natural gas transmission operations beginning in 1982
through a wholly-owned subsidiary, Sunburst Energies, Inc. During fiscal
1992, the Company's Board of Directors voted to discontinue gas transmission
operations. In connection therewith, effective March 31, 1993, the Company
sold its gas transmission segment to an unrelated third party for $20,000
cash, retaining responsibility for litigation in progress at that time. The
Company has reported the financial results through that date, the loss on the
sale and the subsequent settlement of such litigation as "Discontinued
Operations" in its consolidated financial statements.
4
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SEGMENT INFORMATION AND MAJOR CUSTOMERS
After the previously discussed discontinuance of the Company's gas
transmission business, the Company has one business segment: Oil and Gas
Exploration, Production and Development. The Company had sales in excess of
10% of total revenues to three unaffiliated oil and gas customers during
fiscal 1995 totaling 40%, two unaffiliated oil and gas customers during
fiscal 1994 totaling 22% and three unaffiliated oil and gas customers during
fiscal 1993 totaling 46%. The Company does not believe that the loss of any
existing purchaser would have a material adverse effect on its financial
condition or results of operations.
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.
NATURAL GAS PRICING. Historically, the Natural Gas Policy Act of 1978
("NGPA") established maximum prices for certain categories of natural gas
sold in either interstate or intrastate commerce and was designed to effect
deregulation of the sales price for certain categories of natural gas.
Substantially all of the Company's natural gas production falls into
categories of gas which were deregulated under the NGPA, so that the NGPA's
ceiling prices were largely inapplicable. The Natural Gas Wellhead Decontrol
Act of 1989 provided for the elimination of all price regulation under the
NGPA effective January 1, 1993. During fiscal 1992, the Federal Energy
Regulatory Commission ("FERC") issued FERC Order No. 636 and subsequent
related Orders (the "Order"), which is intended to ensure that pipelines
provide transportation service that is equal in quality for all gas supplies,
whether the customer purchases the gas from the pipeline or from a different
supplier. While the Company views this Order as favorable to natural gas
producers, it cannot quantify the impact, if any, it has had or will have on
the Company.
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.
Recently adopted regulations have, however, resulted in the Company's
election to expend additional funds in its continuing effort to comply in all
respects with applicable environmental legislation and regulations. During
fiscal 1994, the Company voluntarily converted its Lea County, New Mexico
saltwater disposal system from surface disposal to subsurface disposal. The
state-authorized discharge and safety monitoring system discharged produced
formation water into a naturally occurring surface playa lake. Although the
Company was not cited for any violations, it is aware that the Environmental
Protection Agency has initiated efforts to eliminate surface disposal of
produced saltwater in certain instances. The Company incurred approximately
$271,000 in costs to effect the conversion. During fiscal 1995, the Company
incurred approximately $44,000 in further costs for remediation of previously
used facilities. Although the Company expects to incur environmental
clean-up expenditures in the future, at this time, it is not aware of any
such expenditures that would have a material adverse effect on its financial
condition or results of operations.
EMPLOYEES
At September 30, 1995, the Company employed a total of 20 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.
5
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ITEM 2. PROPERTIES
OIL AND GAS PROPERTIES
PRODUCING OPERATIONS
STRATEGY. During its fiscal years ended September 30, 1991, 1992 and 1993,
the Company's basic strategy was to increase oil and gas reserves through the
acquisition of producing domestic oil and gas properties. Where feasible,
the Company sought to acquire producing properties that had additional
production potential through implementation of various exploitation
techniques and through further development. The Company's geographic focus
was primarily the Rocky Mountain and Mid-Continent regions. Based on
publicly available information and management's experience, the Company
believes that many of the major integrated and large independent oil
companies were shifting their investment emphasis internationally and
consolidating their domestic operations to reduce costs. These factors,
among others, created opportunities for oil and gas entities such as the
Company to add reserves through the acquisition of producing oil and gas
properties divested by these larger companies. During fiscal 1994, however,
the number of such property dispositions in the Company's target size and
price range decreased significantly, and competition to purchase such
available properties intensified. During the same period, the Company's
activities and capital expenditures shifted toward domestic and international
exploratory and developmental drilling projects and have continued to be so
focused. The Company believes it has the skills to take advantage of both
exploration and property acquisition opportunities, particularly within its
geographic areas of emphasis. While it plans to pursue both strategies, the
availability of producing properties offered for sale in the future is
indeterminable, and the Company currently has only minimal borrowing capacity
under its present bank credit facility for the financing of such
acquisitions. The Company continues to periodically review acquisition
opportunities, particularly from companies and individuals who own interests
in wells in which the Company already owns a substantial working interest.
In evaluating prospective producing property acquisitions, the Company
generally focuses on estimates of reserves and future cash flow from the
properties and the internal rate of return expected to be generated by the
properties in their existing condition. Potential for enhancement of the
value of the properties through various exploitation techniques is considered
as well. Exploratory and development drilling opportunities are also
evaluated based upon estimated rates of return, as well as estimated
potential reserves and associated risk levels.
Following is a brief description of the Company's major producing areas:
LEA COUNTY, NEW MEXICO. The Company commenced oil and gas operations in Lea
County, New Mexico in 1969 when it first acquired interests in the North
Bagley Field. After purchasing additional interests throughout the field in
1984, North Bagley became and today remains the Company's largest single
operated property. As of September 30, 1995, the Company's North Bagley
properties had a present value of estimated future net revenues of
$2,284,000, representing approximately 9% of the Company's total reserve
value.
The Company's North Bagley reserves are evenly distributed among the 39 wells
currently operated by the Company. Current net daily production represents
approximately 9% and 26%, respectively, of the Company's total daily oil and
gas production. Management believes that, although the field is mature, it
may have some potential for further exploitation.
In addition to North Bagley, the Company owns and operates properties in
several other Lea County fields, including the Mescalero, Shipp and Northeast
Lovington fields.
TEXAS. The Company has been active in Texas for over 20 years. The majority
of the Company's Texas properties are located in the Permian Basin in west
Texas and in the West Buna Field in southeast Texas.
In the Permian Basin, of particular importance to the Company are its
properties in the Gustav Field located in Schleicher County, Texas. The
Company's 50% interest in this field was purchased in May 1991. Gas
production is from a series of the Canyon Sands at approximately 7,100 feet.
Subsequent to the initial acquisition, five development wells have been
drilled and completed as producers. The Company's eight gross (4.1 net)
wells in the Gustav Field represent approximately 2% of the Company's present
value of future net revenues and approximately 5% of its total daily gas
production as of September 30, 1995. Subsequent to year end the Company
participated
6
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for its 10% interest in a new gas discovery near the Gustav field and expects
to join in the drilling of at least one development well in fiscal 1996.
The West Buna Field in Jasper and Hardin Counties represents a significant
percentage of the Company's Texas reserves. The Company's nonoperating
interest in this field was acquired on August 31, 1993. Total discounted
future net revenues from the property were $4,638,000, approximately 19% of
the Company's total, as of September 30, 1995. Of this total, $1,894,000 was
attributable to proved undeveloped reserves. Both oil and gas volumes and
discounted future net revenues applicable to proved undeveloped reserves and
proved developed nonproducing reserves were reduced significantly as of
September 30, 1994, based upon water encroachment into a producing wellbore
during fiscal 1994. No further reserve reductions of a similar nature were
necessary as of September 30, 1995. During fiscal 1995, net oil and gas
production from this field were approximately 5% and 11%, respectively, of
the Company's total.
WILLISTON BASIN, NORTH DAKOTA AND MONTANA. In 1991, the Company became
active in the Williston Basin when it acquired various interests in five
different fields for $1,700,000. In April 1993, the Company increased its
operating activities in the Williston Basin when it acquired interests in the
Charlson and Keene Fields located in McKenzie County, North Dakota for
approximately $1,300,000. On September 30, 1993, the Company acquired
producing oil and gas properties and other assets for approximately
$11,000,000, the majority of which were in the Williston Basin. The Company
now operates 44 wells in the Williston Basin of North Dakota and Montana.
The Company has established additional reserves since acquisition through
recompletion in different formations through existing wellbores and is
presently evaluating these properties for further behind-pipe and in-fill
development potential. With discounted future net revenues of approximately
$5,981,000, the Company's Williston Basin assets now comprise approximately
24% of the Company's total reserve value at September 30, 1995, and account
for 36% of the Company's daily oil production and 18% of its daily gas
production.
POWDER RIVER BASIN, WYOMING. The Powder River Basin in northeastern Wyoming
has been an area of active interest for the Company since October 1991, when
it joined with three other companies to acquire both producing properties and
undeveloped acreage. The Company's strategy in the Powder River Basin
reflects management's belief that this relatively mature basin still holds
significant potential for select acquisitions, exploitation and development
drilling. On May 14, 1993, the Company acquired a 47% working interest in a
Powder River Basin Minnelusa waterflood property for $435,000. On September
30, 1993, the Company acquired another significant producing property in the
Powder River Basin which, as of September 30, 1995, had discounted future net
revenues of $2,168,000, or 9% of the Company's total reserve value.
The Company's total acquisition cost in the area over the past four fiscal
years is approximately $4 million, and additional capital has been invested
in development drilling projects. Net production from the Powder River Basin
accounts for approximately 21% of the Company's daily oil production. The
Company now owns nonoperating interests in eight waterflood projects in this
area.
SAN JUAN BASIN, NEW MEXICO AND COLORADO. On July 30, 1993, the Company
acquired a nonoperating interest in producing gas properties in southwestern
Colorado and northwestern New Mexico for approximately $1,800,000. The
majority of these properties were sold for approximately $4,500,000 on May 1,
1995. The sale represented approximately 4% of the Company's total
discounted future net revenues and 437,000 barrels of oil equivalent ("BOE"),
or 7% of the Company's total proved reserve volumes as of September 30, 1994.
Under the full cost method of accounting, no gain or loss was recognized on
the property sale; the proceeds were credited to the full cost pool, thereby
reducing the book value of the Company's oil and gas properties. While this
sale substantially reduced the Company's assets in this area, proved gas
reserves at September 30, 1995 of approximately 1.8 Bcf still represented
approximately 14% of the Company's total proved gas reserves, and average
daily production of approximately 600 Mcf represents 13% of the Company's
total.
7
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The following table sets forth information with respect to the Company's
producing wells and acreage as of September 30, 1995:
<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>
Alabama 12 .67 - - 2,647 179 1,758 490
Alaska(1) - - - - - - 3,783 173
Colorado 64 4.81 9 .31 16,969 766 70,373 65,361
Indiana - - - - - - 9,548 835
Louisiana 6 1.16 6 .41 5,269 592 - -
Montana 50 6.49 - - 9,274 1,697 45,155 39,057
Nebraska 8 1.70 - - 1,719 365 640 123
Nevada - - - - 3,840 38 3,840 77
New Mexico 66 46.31 258 7.33 18,069 4,905 5,479 1,036
North Dakota 75 18.77 - - 18,178 4,500 4,720 5,991
Oklahoma 9 2.49 15 .78 6,940 1,596 215 79
Texas 43 4.78 46 7.64 16,941 2,557 1,326 383
Wyoming 60 5.32 1 .03 30,796 1,188 14,470 3,871
Australia(2) - - 16 4.80 - - - -
--- ----- --- ----- ------- ------ ------- -------
Total 393 92.50 351 21.30 130,642 18,383 161,307 117,476
--- ----- --- ----- ------- ------ ------- -------
--- ----- --- ----- ------- ------ ------- -------
</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 10 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) The Company owns a nonoperating interest in an Authority to Prospect
("ATP") covering approximately 1,365,000 acres in the Bowen Basin of
Queensland, Australia. The Company's interest bears 30% of capital costs and
28.125% of operating expenses and its net revenue interest is 25.3125% prior
to project payout. Subsequent to project payout, the Company's interest
bears 24% of capital and operating expenses and its net revenue interest is
21.6%. The Company and its co-venturers (the "Group") have applied for
petroleum leases covering approximately 167,000 acres. The balance of
acreage included within the ATP is subject to contraction or relinquishment
on certain dates in the future should the Queensland Minister of Mines deem
that insufficient exploration activity has occurred. The Group intends to
request extensions of any contraction of the ATP based upon the significant
level of investment and activity conducted in the past two years and that
planned for the future. The next scheduled contraction date is November 1,
1996. The Company is currently a party to litigation involving this acreage;
see Note 8 to the Company's Consolidated Financial Statements.
The Company's domestic undeveloped leases have various primary terms ranging
from one to ten years. The expiration of any certain leasehold interest or
interests would not have a material adverse financial effect on the Company.
Substantially all of the Company's domestic oil and gas properties either
have been or may be pledged as security for bank debt. While mortgages have
not been filed against many of the properties, additional mortgages will be
filed as the Company's bank requires. See Note 5 to the Company's
Consolidated Financial Statements.
8
<PAGE>
EXPLORATORY OPERATIONS
INTERNATIONAL
In April 1992, the Company acquired a nonoperating interest in the Comet
Ridge coalbed methane project in Queensland, Australia. The joint venture
conducting the project (the "Group") owns an Authority to Prospect ("ATP")
covering approximately 1,365,000 acres. The holder of the ATP may be granted
petroleum leases upon establishing to the satisfaction of the Queensland
government that commercial deposits of petroleum have been discovered. The
Group has applied for and posted deposits on petroleum leases covering
approximately 167,000 acres and expects to receive them in early calendar
1996. Drilling operations commenced in November 1993, when one noncommercial
well was drilled on adjacent farmout acreage that has since been
relinquished. During fiscal 1994, two wells were drilled and, in fiscal
1995, an additional 14 wells were drilled, all within the Group's original
ATP. Fourteen of the wells in the Fairview area have now been completed and
are currently being production tested. Most have been produced for several
months for the purpose of gathering data relative to gas and water production
rates and estimated recoverable gas reserves. Reservoir modeling, combined
with evaluation of actual production performance data, has allowed
independent reservoir engineers to assign technically recoverable reserve
volumes to the 14 core Fairview area wells. Although the Company has not
included these reserves in its proved reserves due to the present lack of a
sales contract and marketing facilities, the Company believes the property is
commercially productive. However, the availability of capital resources may
affect the Company's timing for future development of the project and there
can be no assurance that the project will be developed as presently
contemplated. The Company's interest bears 30% of capital costs and 28.125%
of operating expenses, and its net revenue interest is 25.3125% prior to
project payout. Subsequent to project payout, the Company's interest bears
24% of capital and operating expenses and its net revenue interest is 21.6%.
In August 1995, the operator of this property, Tri-Star Petroleum Company
("Tri-Star"), initiated litigation against the Company and one other
participant alleging that the two parties have forfeited their interest in
the project except for their interest in existing wells. The Company has
filed its original answer and counterclaim denying the allegations and
seeking declaratory judgment with respect to several issues and injunctive
relief prohibiting the operator from transferring or purporting to transfer
the Company's interest in the project to a third party. The Company believes
the suit is without merit and is vigorously defending its interest in the
project. See Note 8 to the Company's Consolidated Financial Statements.
DOMESTIC
On July 29, 1994, the Company acquired an undivided 87.5% working interest in
nonproducing oil and gas leases covering approximately 30,000 acres and has
subsequently leased approximately 15,000 additional acres in its Missouri
River Project area. Approximately 30% of this area, located in the Williston
Basin of Montana, has been evaluated using 3-D seismic technology. The
Company's cost of acquiring the acreage and conducting the seismic survey is
approximately $1,815,000. Drilling operations are now being planned on two
prospects based upon structural anomalies indicated by the seismic survey.
The Company is considering conveying a portion of the project to third
parties for cash prior to drilling but plans to maintain its present 87.5% if
suitable terms are not reached.
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 1995, 1994
and 1993 is included in Note 10 to the Company's Consolidated Financial
Statements. In fiscal 1995, information concerning portions of the Company's
estimated proved oil and gas reserves was also provided to the U.S.
Department of Energy.
OTHER BUSINESS PROPERTIES
NGL FRACTIONATING PLANT INVESTMENT. On August 19, 1994, the Company entered
into an agreement with three other parties to form a Utah limited liability
company ("LLC") for the purpose of constructing a natural gas liquids ("NGL")
fractionating facility (the "Plant") in Alabama. The LLC simultaneously
entered into an agreement with two other parties to form an Alabama limited
liability company to construct and operate the Plant. The Company committed
to contribute $1,148,000 in cash in return for a 45% interest in Plant profits
prior to payout of its
9
<PAGE>
investment and a 27% interest thereafter. During fiscal 1995, following
certain cost overruns and construction delays, the Company agreed to increase
its investment in connection with a restructuring of the Plant ownership. As
of September 30, 1995, the Company had invested $1,454,000, which investment
had increased to $1,939,000 subsequent to year end. Subsequent to the
restructuring, the Company expects to own an interest in the Plant of between
50% and 55% prior to payout and an interest of between 37% and 47%
thereafter. The Plant commenced testing operations in November 1995 and is
expected to go on full production prior to calendar year end.
ENVIRONMENTAL CLEANUP TECHNOLOGY. The Company paid and charged to expense
approximately $40,000, $112,000 and $233,000 in fiscal 1995, 1994 and 1993,
respectively, to Texas Tech University ("Texas Tech") and other parties to
fund a research project for the further development of a new oil spill
cleanup technology. The technology is designed to biodegrade absorbent
materials utilized in the containment and cleanup of oil spills and to
release absorbed oil to the liquid phase. Additional studies relating to the
separation, treatment and recovery of the released oil have been conducted by
Texas Tech. The procedure has been performed successfully in a laboratory
environment. Management believes that such a process, if proven to be
commercial, could be significant in connection with degradation and/or
reduction of oil saturated material that must be disposed of in toxic
landfills. The Company has the right to acquire exclusive licensing rights to
the technology for no additional consideration, subject to a maximum 10%
sales royalty to be paid to Texas Tech. While the Company has no further
research funding commitments, it has recently incurred a $30,000 commitment
in connection with the engagement of an international environmental research
firm to identify and evaluate commercial opportunities for this technology.
CHINA JOINT VENTURE. The Company entered into a joint venture agreement with
unrelated parties to identify low cost exploration prospects for oil and gas
reserves in mainland China through April 30, 1995. The operator has
conducted preliminary operations necessary to develop and obtain land
information and geological, geophysical and other related data for the
purpose of initiating and conducting exploration and development projects.
The Company has contributed $38,000 to the joint venture pursuant to a
maximum commitment of $102,000 and will have the option to participate for up
to 15% of the joint venture's participation in any prospect. Management
anticipates that the venture will attempt to prospect for coalbed methane in
mainland China, although no projects have been initiated to date and the
project is currently dormant.
BAUXITE INTEREST. The Company owns a royalty interest in an undeveloped
Australian bauxite property equal to $0.50 per metric ton of bauxite mined
subject to certain limitations. No mining operations are anticipated in the
foreseeable future, nor does the Company expect to devote substantial
attention to this property.
OFFICE FACILITIES. The principal executive offices of the Company are at 633
Seventeenth Street, Suite 1550, Denver, Colorado 80202, where it leases
approximately 11,000 square feet of office space from an unaffiliated party.
ITEM 3. LEGAL PROCEEDINGS
Information concerning legal proceedings involving the Company is included in
Note 8 to the Company's Consolidated Financial Statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Company did not submit any matter to a vote of its security holders
during the fourth quarter of its fiscal year ended September 30, 1995.
10
<PAGE>
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
The Company's common stock was listed and began trading on the American Stock
Exchange on April 16, 1992. Prior to that time, the stock traded in the
Over-The-Counter Market on the Nasdaq System. As of December 1, 1995, there
were approximately 3,000 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 1995 1994
------------- ------------ ------------
High Low High Low
---- --- ---- ---
<S> <C> <C> <C> <C>
December 31 $4.19 $2.44 $7.13 $2.50
March 31 $7.13 $3.38 $3.38 $2.25
June 30 $7.63 $4.81 $2.88 $2.13
September 30 $5.75 $4.06 $4.06 $2.63
</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 was amended during fiscal 1994 to provide that dividends may
not be paid by the Company without the prior approval of the bank. The
Company intends to retain its earnings to provide funds for operations and
expansion of its business.
11
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
Selected financial data (in thousands, except per share data) for each of the
years in the five-year period ended September 30, 1995 is as follows:
<TABLE>
<CAPTION>
1995 1994 1993 1992 1991
------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
Revenues from continuing
operations $11,837 $13,884 $ 9,499 $ 7,553 $ 7,155
------- ------- ------- ------- -------
------- ------- ------- ------- -------
Income (loss) from:
Continuing operations $(1,284) $(1,638)(1) $ 1,308 $ 1,402 $ 1,146
Discontinued operations - (214) 675 8,269(3) (608)
Extraordinary items(4) - - 881 4,973 361
Cumulative effect of
accounting change - 3,000 (2) - - -
------- ------- ------- ------- -------
Net income (loss) $(1,284) $ 1,148 $ 2,864 $14,644 $ 899
------- ------- ------- ------- -------
------- ------- ------- ------- -------
Primary income (loss) per
common share:
Continuing operations $ (.11) $ (.15) $ .13 $ .15 $ .13
Discontinued operations - (.02) .07 .90 (.07)
Extraordinary items - - .09 .54 .04
Cumulative effect of
accounting change - .27 - - -
------- ------- ------- ------- -------
Net income (loss) $ (.11) $ .10 $ .29 $ 1.59 $ .10
------- ------- ------- ------- -------
------- ------- ------- ------- -------
Weighted average shares
outstanding 11,190 11,311 9,982 9,228 8,934
------- ------- ------- ------- -------
------- ------- ------- ------- -------
Total assets $47,044 $48,253 $48,862 $23,000 $15,316
------- ------- ------- ------- -------
------- ------- ------- ------- -------
Total long-term debt $15,746 $15,746 $17,696 $ 4,189 $11,585
------- ------- ------- ------- -------
------- ------- ------- ------- -------
Working capital $ 5,455 $ 4,965 $ 4,081 $ 7,854 $ 2,840
------- ------- ------- ------- -------
------- ------- ------- ------- -------
Working capital provided
by operations $ 3,917 $ 5,097 $ 5,050 $16,378 $ 2,449
------- ------- ------- ------- -------
------- ------- ------- ------- -------
Stockholders' equity $29,818 $31,031 $29,678 $17,623 $ 2,923
------- ------- ------- ------- -------
------- ------- ------- ------- -------
</TABLE>
(1) Includes $2,021 write-down of oil and gas properties.
(2) Change in method of accounting for income taxes.
(3) Includes gain on settlement of litigation of $14,800, offset by income
tax expense of $4,952 and other expenses.
(4) Amounts for fiscal 1993, 1992 and 1991 represent tax benefit of net
operating loss carryforwards.
12
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
GENERAL
During the past two fiscal years, the Company's primary focus has shifted
from the acquisition of producing oil and gas properties to exploratory and
development drilling activities. Producing property acquisitions, which
totaled approximately $26.6 million during fiscal 1993, decreased to $323,000
and $207,000 in fiscal years 1994 and 1995, respectively. This decrease in
acquisition activity can be attributed to the following: a decrease in the
availability of producing properties offered for sale in the Company's target
size and price range; the Company's limited capital resources and borrowing
capacity; and the Company's commencement of significant exploratory
activities discussed below. Producing property acquisitions were financed
through cash on hand, the sale of common stock (see below and Note 6 to the
Company's Consolidated Financial Statements) and bank financing. From
September 30, 1992 to September 30, 1993, long-term debt increased from
$4,189,000 to $17,696,000, representing bank borrowing used to partially
finance producing property acquisitions. After $1,950,000 in principal
reductions in fiscal 1994, the bank loan balance has remained at $15,746,000
through September 30, 1995, as the Company's available cash and cash flow
have been utilized primarily for capital expenditures.
Proved oil and gas reserves decreased from 3,685,000 barrels and 15.6 Bcf,
respectively, as of September 30, 1994 to 3,419,000 barrels and 13.1 Bcf,
respectively, as of September 30, 1995. Total discounted future net revenues
decreased from $29,021,000 as of September 30, 1994 (using prices as of that
date) to $24,200,000 as of September 30, 1995. A significant portion of the
decrease in reserve volumes is attributable to two separate sales of
producing properties. See Note 3 to the Company's Consolidated Financial
Statements. Additionally, proved developed producing reserves decreased as a
result of normal production without replacement of reserves. The decrease in
discounted future net revenues was likewise attributable to these volume
decreases as well as lower oil prices at September 30, 1995, compared to
September 30, 1994. See Note 10 to the Company's Consolidated Financial
Statements.
The Company's domestic development activity during fiscal 1995 continued to
be directed primarily toward the exploitation of properties previously
acquired. The Company has established additional proved reserves through both
recompletions in different formations in existing wellbores and the drilling
of additional wells. Management believes that further reserve additions may
result from such ongoing activity.
The Company's increasing investment in exploration projects during fiscal
1995 was directed primarily to the following:
DOMESTIC EXPLORATION. During fiscal 1995, the Company acquired an 87.5%
undivided interest in an additional 9,000 acres in its Missouri River
Project area in the Williston Basin of Montana. A 3-D seismic survey was
conducted over approximately 30% of the area, resulting in the
identification of several drillable prospects. The Company has permitted
and staked well locations to test two of the prospects and is currently
seeking to involve third parties to participate in the drilling after
payment to the Company of an initial cash purchase price. If a suitable
agreement is not reached with a third party, the Company intends to begin
drilling operations with its existing 87.5% interest. As of September 30,
1995, the Company's investment in the project totaled approximately
$1,815,000.
INTERNATIONAL EXPLORATION. In April 1992, the Company acquired a 30%
nonoperating interest in the Comet Ridge coalbed methane project in
Queensland, Australia. The Company's interest bears 30% of capital costs
and 28.125% of operating expenses, and its net revenue interest is
25.3125% prior to project payout. Subsequent to project payout, the
Company's interest bears 24% of capital and operating expenses and its
net revenue interest is 21.6%. The joint venture conducting the project
(the "Group") owns an Authority to Prospect ("ATP") covering approximately
1,365,000 acres. The holder of the ATP may be granted petroleum leases
upon establishing to the satisfaction of the Queensland government that
commercial deposits of petroleum have been discovered. Drilling operations
commenced in November 1993 when one noncommercial well was drilled on
adjacent farmout acreage that has since been relinquished. During fiscal
1994, two wells were drilled, and
13
<PAGE>
in fiscal 1995, an additional 14 wells were drilled within the Group's
original ATP. Fourteen of the wells located in the core Fairview area
of the southern portion of the ATP have been completed and are being
production tested. Most have been produced for several months for the
purpose of gathering data relative to gas and water production rates and
estimated recoverable gas reserves. Reservoir modeling, combined with
evaluation of actual production performance data, has allowed independent
reservoir engineers to assign technically recoverable reserve volumes to
the 14 core Fairview area wells. Although the Company has not included
these reserves in its proved reserves due to the present lack of a sales
contract and marketing facilities, the Company believes the property is
commercially productive. The availability of capital resources may affect
the Company's timing for future development of the project, and there can
be no assurance that the project will be developed as presently
contemplated. The Group has applied for petroleum leases covering
approximately 167,000 acres. The balance of acreage included within the
ATP is subject to contraction or relinquishment on certain dates in the
future should the Queensland Minister of Mines deem that insufficient
exploration activity has occurred. The Group intends to request
extensions of any contraction of the ATP based upon the significant level
of investment and activity conducted in the past two years and that planned
for the future. The next scheduled contraction date is November 1, 1996.
In August 1995, the operator of this property initiated litigation against
the Company and one other participant alleging that the two parties have
forfeited their interest in the project except for their interest in
existing wells by failing to notify the operator of their participation
in, and make payment for, certain seismic operations. The Company believes
the suit is without merit and is vigorously defending its interest in the
project. See Note 8 to the Company's Consolidated Financial Statements.
As of September 30, 1995, the Company's investment in the project totaled
approximately $5,125,000.
On August 19, 1994, the Company entered into an agreement with three other
parties to form a Utah limited liability company ("LLC") for the purpose of
constructing a natural gas liquids ("NGL") fractionating facility (the
"Plant") in Alabama. The LLC simultaneously entered into an agreement with two
other parties to form an Alabama limited liability company to construct and
operate the Plant. The Company committed to contribute $1,148,000 in cash,
in return for a 45% interest in Plant profits prior to payout of its
investment and a 27% interest thereafter. During fiscal 1995, following
certain cost overruns and construction delays, the Company agreed to increase
its investment in connection with a restructuring of the Plant ownership. As
of September 30, 1995, the Company had invested $1,454,000, which investment
increased to $1,939,000 subsequent to year end. Subsequent to the
restructuring, the Company expects to own an interest in the plant of between
50% and 55% prior to payout and an interest of between 37% and 47%
thereafter. The plant commenced testing operations in November 1995 and is
expected to go on full production prior to calendar year end.
The Company paid and charged to expense approximately $40,000, $112,000 and
$233,000 in fiscal 1995, 1994 and 1993, respectively, to Texas Tech
University ("Texas Tech") and other parties to fund a research project for
the further development of a new oil spill cleanup technology. The
technology is designed to biodegrade absorbent materials utilized in the
containment and cleanup of oil spills and to release absorbed oil to the
liquid phase. Additional studies relating to the separation, treatment and
recovery of the released oil have been conducted by Texas Tech. The
procedure has been performed successfully in a laboratory environment.
Management believes that such a process, if proven to be commercial, could be
significant in connection with degradation and/or reduction of oil saturated
material that must be disposed of in toxic landfills. The Company has the
right to acquire exclusive licensing rights to the technology for no
additional consideration, subject to a maximum 10% sales royalty to be paid
to Texas Tech. While the Company has no further research funding
commitments, it has recently incurred a $30,000 commitment in connection with
the engagement of an international environmental research firm to identify
and evaluate commercial opportunities for this technology. Patent
applications have been submitted and are currently pending.
On March 31, 1995, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" ("FAS 121").
FAS 121 established accounting standards for the impairment of long-lived
assets to be held or disposed of. Although the Statement does not apply to
oil and gas properties under the full cost method of accounting, it applies
to other assets of the Company. Adoption is required for the Company's first
quarter of fiscal 1997. The effects of adoption, if any, are unknown at this
time.
14
<PAGE>
LIQUIDITY AND CAPITAL RESOURCES
For the three years ended September 30, 1995, 1994 and 1993, cash flows from
operating activities were $5,158,000, $4,392,000 and $4,198,000,
respectively. In fiscal 1993, the Company expended $31,724,000 for property
acquisitions and other minor capital items. Bank borrowings of $15,650,000
were used to partially finance these acquisitions along with a common stock
offering which netted proceeds of $9,191,000. During fiscal 1994, proceeds
from the sale of noncore oil and gas properties totaled $1,725,000. Capital
expenditures totaled $4,208,000, of which $646,000 was attributable to the
Company's Australia coalbed methane exploration project and $1,008,000 was
attributable to the Company's Williston Basin 3-D seismic project. The
balance was expended primarily on various development drilling activities and
minor producing property acquisitions. The Company expended $1,950,000 in
repayment of bank debt and $71,000 for the repurchase of its common stock on
the open market. See Note 6 to the Company's Consolidated Financial
Statements. During fiscal 1995, the Company sold producing oil and gas
properties in two separate transactions generating net cash sales proceeds of
approximately $5,100,000. These funds in combination with cash flows from
operations were primarily utilized to fund capital expenditures of
approximately $7,253,000. Of this total, $4,312,000 was expended on the
Company's Australia coalbed methane project, $807,000 on the Williston Basin
3-D seismic project and $1,138,000 was invested in the Alabama gas
fractionating plant, with the balance attributable primarily to development
drilling.
As of September 30, 1995, the Company had cash and temporary investments
totaling $4,193,000 and total long-term debt of $15,746,000. The Company's
current cash position coupled with current monthly operating cash flows will
be utilized to fund current oil and gas exploration and development
activities in the near term. The Company is also discussing with third
parties the possibility of obtaining additional financing through corporate
and/or project level financing.
The Company's bank credit agreement provides a maximum facility of
$40,000,000, subject to borrowing base limitations described below. At the
Company's option, interest is payable at either the bank's Base Rate or
London Interbank Offered Rate ("LIBOR") plus 1.5%. The LIBOR-based option
may be selected for periods not exceeding 90 days. At September 30, 1995, the
weighted average interest rate for amounts under the revolver was 7.66%. The
agreement provides for a $10,000,000 fixed rate loan at 5.92%, with interest
payable monthly and principal due in full on September 30, 1996. The bank and
the Company have agreed that upon maturity of the fixed rate loan, it will
convert to a revolving loan pursuant to the current terms of the revolver.
The total outstanding loan balance at September 30, 1995 was $15,746,000;
$10,000,000 under the fixed rate loan and $5,746,000 under the LIBOR/Base
Rate loan. Upon the expiration of the revolver, the loan converts to a
four-year term loan on April 5, 1997. 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 not agree with the Company's assumptions. At September 30, 1995, the
borrowing base remained at $16,400,000, but was being reviewed by the bank;
it is expected by management to be reset at approximately $16,000,000 in
January 1996. Should the outstanding loan balance ever exceed the borrowing
base, the Company is required to either (i) make a cash payment to the bank
equal to or greater than such excess or (ii) provide additional collateral to
the bank to increase the borrowing base by the amount of the deficit. The
Company is obligated to pay a commitment fee of 3/8% per annum on the
difference between the average outstanding loan balance and the nominated
borrowing base. During fiscal 1995, the Company and the bank entered into an
amendment to the credit facility which extended the conversion of the
revolving loan to a term loan from April 5, 1996 to April 5, 1997. A fiscal
1994 amendment added a provision which does not allow the Company to pay
dividends without the prior approval of the bank.
Although adverse events such as product price decreases would negatively
impact cash flows, the Company typically uses hedging techniques to reduce
the effects of such risk. As of September 30, 1995, all hedging agreements
in place during fiscal 1995 expired. Subsequent to September 30, 1995, the
Company hedged, under two swap agreements, 10,000 barrels per month
(approximately 25%) of its oil production volumes from December 1, 1995
through September 30, 1996 at an average floor price of $16.15 per barrel.
These hedging agreements allow the Company upside participation percentages
of 50% of price increases above the floor level. These hedge prices are as
quoted on the New York Mercantile Exchange ("NYMEX"). During fiscal 1995,
the Company hedged an average of 14,167 barrels (approximately 30%) of its
oil production. The Company's actual price received at the wellhead during
fiscal 1995 averaged approximately $2.53 per barrel below NYMEX prices. None
of the Company's gas production was hedged during fiscal 1995 or as of
September 30, 1995. Net receipts (payments) pursuant to the Company's
hedging activities for fiscal 1995, 1994 and 1993 were $(183,000), $182,000
and $(14,000), respectively.
15
<PAGE>
Notwithstanding the Company's hedging positions, decreases in oil and gas
prices subsequent to September 30, 1995 could cause a significant reduction
in cash flows available for exploratory and development drilling and bank
debt service and could negatively impact the Company's efforts to secure new
financing sources.
During fiscal 1996, the Company intends to focus its efforts primarily on its
major domestic and international exploration projects previously discussed.
Due to the minimal remaining unused bank borrowing capacity, the Company will
attempt to establish additional oil and gas reserves in its exploration
projects, thereby increasing borrowing capacity. The Company may also
generate cash flow from its Montana 3-D seismic project prior to drilling by
conveying a portion of its interest to a third party. By utilizing a portion
of projected fiscal 1996 cash flows and possibly project financing for
further drilling on the Comet Ridge coalbed methane project, the Company
hopes to establish proved gas reserves and additional cash flow from the
Australia project as well. In addition to these sources of capital, the
Company may seek to raise capital through new equity and/or debt offerings.
The Company does not expect to pay significant federal income tax in the near
term due to its net operating loss ("NOL") carryforwards. The utilization of
these carryforwards reduces the Company's effective federal tax rate from
approximately 35% to approximately 2%. The carryforwards total approximately
$43,619,000 as of September 30, 1995 and expire over the period from fiscal
1998 through fiscal 2009. These carryforwards would be subjected to a
significant annual limitation should there be a change of over 50% in the
stock ownership of the Company during any three-year period. The Company
adopted SFAS 109 in the first quarter of fiscal 1994, effective retroactive
to October 1, 1993. Because of the Company's significant NOL and other
carryforwards, the Company recorded a deferred tax asset for the
carryforwards under SFAS 109. Since the Company's profitability is not
assured, the deferred tax asset was reduced by a valuation allowance. After
valuation, the net deferred tax asset recorded on the October 1, 1993 balance
sheet was $3,000,000. This amount was reflected in net income as the
cumulative effect of the change in method of accounting for income taxes.
The realization of the asset will have the effect of reducing future earnings
through a charge in lieu of income taxes. During fiscal 1994, the Company
recognized a net benefit of $191,000 due to adjustments to the net deferred
tax asset. Fiscal 1995 results include neither a deferred income tax expense
nor benefit. The Company will continue to review income trends and projected
NOL carryforwards utilizations in order to refine the calculation of the net
amount of the deferred tax asset to be recorded under SFAS 109.
The Company anticipates that in order to complete its capital projects and
sustain growth, internal cash flow and bank financing will have to be
supplemented with project financing and/or additional corporate debt or
equity offerings. The Company presently anticipates using cash on hand,
existing cash flows, additional bank financing and any additional external
financing to pursue both its domestic and international exploratory projects,
to possibly purchase additional producing oil and gas properties, and to
maintain a modest level of developmental drilling.
The Company does not believe that inflation has had a material adverse effect
on its operations during the last three years.
RESULTS OF OPERATIONS
COMPARISON OF THE FISCAL YEARS ENDED SEPTEMBER 30, 1995 AND 1994
The Company reported a net loss of $1,284,000 in fiscal 1995 versus net
income of $1,148,000 in fiscal 1994. If the effects of a change in method of
accounting, discontinued operations, and a writedown of the book value of oil
and gas properties were excluded from fiscal 1994 numbers, the Company would
have reported net income of $383,000. Following are detailed comparisons of
the components of the respective periods.
Operating revenues decreased $2,047,000, or 15%, to $11,837,000 in fiscal
1995 from $13,884,000 in fiscal 1994. Oil volumes decreased 13% to 565,000
barrels in fiscal 1995 from 646,000 barrels in fiscal 1994, resulting in a
$1,191,000 revenue decrease. Gas volumes decreased 18% to 2,061,000 Mcf in
fiscal 1995 from 2,500,000 Mcf in fiscal 1994, resulting in a $724,000
revenue decrease. These volume decreases are attributable to both the sale
of producing properties and to natural declines in oil and gas production
rates. Average oil prices increased 5% to $15.43 in fiscal 1995 from $14.70
in fiscal 1994, resulting in a revenue increase of $412,000. Average gas
prices decreased 13% to $1.43 in fiscal 1995 from $1.65 in fiscal 1994,
resulting in a $453,000 revenue decrease. Changes in other revenues accounted
for an additional $91,000 decrease in total revenues.
16
<PAGE>
Operating expenses decreased $425,000, or 7%, to $5,836,000 in fiscal 1995
from $6,261,000 in fiscal 1994. The decrease was primarily attributable to
sales of producing properties. The Company's average lifting cost per
equivalent barrel produced, however, increased 8% to $6.14 in fiscal 1995
from $5.70 in fiscal 1994. This increase was attributable primarily to
declining production rates and maintenance work performed on mature
properties.
Costs and expenses for fiscal 1994 included a write-down of the book value of
the Company's oil and gas properties pursuant to full cost ceiling test
rules. No write-down was required for fiscal 1995 since the ceiling test
value as of September 30, 1995 exceeded the book value. See Note 3 to the
Company's Consolidated Financial Statements.
General and administrative expenses remained relatively flat, decreasing
$21,000, or 2%, to $1,297,000 in fiscal 1995 from $1,318,000 in fiscal 1994.
Depreciation, depletion and amortization ("DD&A") expense increased $75,000,
or 1%, to $5,197,000 in fiscal 1995 from $5,122,000 in fiscal 1994,
primarily due to an increase in the rate per equivalent barrel. The DD&A
rate per equivalent barrel increased due to the calculation of fiscal 1995
reserves using a lower oil price than that used for fiscal 1994 reserves,
thus decreasing economically recoverable reserves, and to the significant
reduction in proved reserves as of September 30, 1994.
Interest expense remained virtually unchanged with a decrease of only $1,000
to $976,000 in fiscal 1995 from $977,000 in fiscal 1994. When capitalized
interest is included, interest expense increased by $79,000. The increase is
primarily attributable to general increases in interest rates. See Note 5 to
the Company's Consolidated Financial Statements.
During fiscal 1995, research and development expenses incurred by the Company
pursuant to its agreement with Texas Tech University decreased $72,000 to
$40,000 from $112,000 in fiscal 1994 because the Company fulfilled its
contractual funding commitment during the fourth quarter of fiscal 1994.
Expenditures incurred since such fulfillment have been voluntary and of
lesser amounts.
COMPARISON OF THE FISCAL YEARS ENDED SEPTEMBER 30, 1994 AND 1993
The Company reported net income of $1,148,000 in fiscal 1994 versus net
income of $2,864,000 in fiscal 1993. The decrease was primarily due to a
write-down of oil and gas properties and increased DD&A in fiscal 1994,
offset by a $3,000,000 favorable adjustment due to a change in accounting
for income taxes. Following are detailed comparisons of the components of
the respective periods.
Operating revenues increased $4,385,000, or 46%, to $13,884,000 in fiscal
1994 from $9,499,000 in fiscal 1993. Oil volumes increased 70% to 646,000
barrels in fiscal 1994 from 379,000 barrels in fiscal 1993, resulting in a
$4,705,000 revenue increase. Gas volumes increased 83% to 2,500,000 Mcf in
fiscal 1994 from 1,367,000 Mcf in fiscal 1993, resulting in a $2,051,000
revenue increase. The volume increases are attributable to acquisitions of
producing properties in September 1993. Average oil prices decreased 17% to
$14.70 in fiscal 1994 from $17.62 in fiscal 1993, resulting in a revenue
decrease of $1,886,000. Average gas prices decreased 9% to $1.65 in fiscal
1994 from $1.81 in fiscal 1993, resulting in a $400,000 revenue decrease.
Changes in other revenues accounted for an additional $85,000 decrease in
total revenues.
Operating expenses increased $2,347,000, or 60%, to $6,261,000 in fiscal 1994
from $3,914,000 in fiscal 1993. The increase was primarily attributable to
the acquisition of oil and gas properties. The Company's average lifting
cost did, however, decrease 9% to $5.70 in fiscal 1994 from $6.28 in fiscal
1993. This decrease was attributable primarily to the acquisition in late
fiscal 1993 of properties with lower lifting costs and remedial work
performed on these properties in fiscal 1993.
General and administrative expenses increased $199,000, or 18%, to $1,318,000
in fiscal 1994 from $1,119,000 in fiscal 1993. This increase is due
primarily to increased payroll costs. As the Company experienced growth
and improved financial condition, salaries and benefits were increased
to levels comparable with peer companies and additional employees were hired.
DD&A expense increased $3,006,000, or 142%, to $5,122,000 in fiscal 1994
from $2,116,000 in fiscal 1993, primarily due to increased production rates
and an increased depletion rate per equivalent
17
<PAGE>
barrel. The depletion rate per equivalent barrel increased due to the
acquisition of properties late in fiscal 1993 at a cost per equivalent barrel
in excess of the prior year's depletion rate, a significant decrease in
proved undeveloped and proved developed nonproducing reserves as of September
30, 1994, and the calculation of fiscal 1994 reserves using lower oil and gas
prices than those used for fiscal 1993 reserves, thus decreasing economically
recoverable reserves.
Fiscal 1994 costs and expenses increased by $2,021,000 compared to fiscal
1993 due to the Company's write-down of the book value of its oil and gas
properties pursuant to full cost ceiling test rules. See Note 3 to the
Company's Consolidated Financial Statements.
Interest expense increased $715,000, or 273%, to $977,000 in fiscal 1994 from
$262,000 in fiscal 1993. Such increase is primarily attributable to
increased bank debt incurred in connection with the acquisition of producing
oil and gas properties and, to a lesser extent, increases in interest rates.
During fiscal 1994, research and development expenses incurred by the Company
pursuant to its agreement with Texas Tech decreased $121,000 to $112,000 from
$233,000 in fiscal 1993 because the Company reached its funding commitment
during the fourth quarter of fiscal 1994.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Company's Consolidated Financial Statements and supplementary financial
data follow page 22 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,
1995 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 22 and is
incorporated herein by reference.
(b) During the last quarter of the Company's fiscal year ended September 30,
1995, the Company filed the following report on Form 8-K:
Form 8-K dated August 11, 1995 incorporating by reference a Press
Release dated August 14, 1995 announcing third quarter and nine
month results and a declaratory judgment action initiated against
Tipperary Oil & Gas Corporation and another party by the operator
of the Comet Ridge project in Queensland, Australia.
(c) Exhibits:
For a list of exhibits, see "Exhibits" which follows page 19 and is
incorporated herein by reference.
18
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
TIPPERARY CORPORATION
Date December 15, 1995 By /s/ Carter G. Mathies
----------------------------------
Carter G. Mathies, 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/ Carter G. Mathies President, Chief Executive Officer December 15, 1995
- --------------------- and Chairman of the Board of Directors
Carter G. Mathies
/s/ David L. Bradshaw Vice President, Chief Operating December 15, 1995
- --------------------- Officer, Chief Financial Officer
David L. Bradshaw and Director
/s/ Wayne W. Kahmeyer Controller and Principal Accounting December 15, 1995
- --------------------- Officer
Wayne W. Kahmeyer
/s/ Eugene I. Davis Director December 15, 1995
- ---------------------
Eugene I. Davis
/s/ Anthony F. Kramer Director December 15, 1995
- ---------------------
Anthony F. Kramer
/s/ Marshall D. Lees Director December 15, 1995
- ---------------------
Marshall D. Lees
/s/ James A. McAuley Director December 15, 1995
- ---------------------
James A. McAuley
</TABLE>
19
<PAGE>
EXHIBITS
<TABLE>
<CAPTION>
NUMBER DESCRIPTION
- ------ -----------
<S> <C>
3.9 Restated Articles of Incorporation of Tipperary Corporation adopted
May 6, 1993, filed as Exhibit 3.9 to Amendment No. 1 to Registration
Statement on Form S-1 filed with the Commission on June 29, 1993,
and incorporated herein by reference.
3.10 Restated Corporate Bylaws of Tipperary Corporation adopted June 28,
1993, filed as Exhibit 3.10 to Amendment No. 1 to Registration
Statement on Form S-1 filed with the Commission on June 29, 1993,
and incorporated herein by reference.
4.37 Second Amendment to Credit Agreement dated September 27, 1991 by and
between Tipperary Petroleum Company and Central Bank, National
Association, formerly Central Bank of Denver, 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 between 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.
10.9 Employment Agreement dated October 1, 1990 between Registrant and
Carter G. Mathies, filed as Exhibit 10.9 to Form 10-K dated September
30, 1990, and incorporated herein by reference.
10.10 Employment Agreement dated October 1, 1990 between Registrant and
David L. Bradshaw, filed as Exhibit 10.10 to Form 10-K dated
September 30, 1990, and incorporated herein by reference.
</TABLE>
20
<PAGE>
EXHIBITS
<TABLE>
<CAPTION>
NUMBER DESCRIPTION
- ------ -----------
<S> <C>
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.
10.19 Purchase and Sale Agreement dated February 29, 1992 by and between
Geodyne Production Company and Tipperary Oil and Gas Corporation, filed
as Exhibit 10.19 to Form 8-K dated March 12, 1992, and incorporated
herein by reference.
10.20 Unit Operating Agreement dated March 1, 1977 effecting the Point
Thomson Unit Area, Alaska, filed as Exhibit 10.20 to Form 8 dated
August 12, 1992, and incorporated herein by reference.
10.21 Amendment to Point Thomson Unit Area Operating Agreement dated June
9, 1977, filed as Exhibit 10.21 to Form 8 dated August 12, 1992, and
incorporated herein by reference.
10.22 Amendment to Point Thomson Unit Area Operating Agreement dated
February 16, 1982, filed as Exhibit 10.22 to Form 8 dated August 12,
1992, and incorporated herein by reference.
10.23 Competitive Oil and Gas lease dated April 1, 1990 by and between the
State of Alaska and Tipperary Land and Exploration Corporation,
effecting the Point Thomson Unit, Alaska, filed as Exhibit 10.19 to
Form 8 dated August 12, 1992, and incorporated herein by reference.
10.24 Amendment dated October 1, 1992 to Employment Agreement dated
October 1, 1990 between Registrant and Carter G. Mathies, filed as
Exhibit 10.24 to Form 10-K dated September 30, 1992, and incorporated
herein by reference.
10.25 Amendment dated October 1, 1992 to Employment Agreement dated
October 1, 1990 between Registrant and David L. Bradshaw, filed as
Exhibit 10.25 to Form 10-K dated September 30, 1992, and incorporated
herein by reference.
10.26 Purchase and Sale Agreement dated December 29, 1992 with Horizon
Natural Gas Company, filed as Exhibit 10.26 to Form 8-K dated
December 29, 1992, and incorporated herein by reference.
10.27 Letter Agreement with BWAB Incorporated regarding Project
Participation, filed as Exhibit 10.27 to Form 8-K dated December 29,
1992, and incorporated herein by reference.
10.28 Letter dated February 25, 1993 by Diamond Energy Operating Company
exercising the Purchase Option, filed as Exhibit 10.28 to Form 8 dated
March 5, 1993, and incorporated herein by reference.
10.29 Purchase and Sale Agreement dated April 15, 1993 with Universal
Resources Corporation, filed as Exhibit 10.26 to the initial
Registration Statement on Form S-1, filed with the Commission on
June 4, 1993, and incorporated herein by reference.
10.30 Purchase and Sale Agreement dated May 4, 1993 with Flahive Oil & Gas
LLC, filed as Exhibit 10.27 to the initial Registration Statement on
Form S-1 filed with the Commission on June 4, 1993, and incorporated
herein by reference.
10.31 Purchase and Sale Agreement dated July 30, 1993 with Whiting
Petroleum Corporation, filed as Exhibit 10.29 to Form 8-K dated
July 30, 1993, and incorporated herein by reference.
10.32 Purchase and Sale Agreement effective July 1, 1993 with Amax Oil &
Gas, Inc., filed as Exhibit 10.30 to Form 8-K dated September 30, 1993,
and incorporated herein by reference.
</TABLE>
21
<PAGE>
EXHIBITS
<TABLE>
<CAPTION>
NUMBER DESCRIPTION
- ------ -----------
<S> <C>
10.33 Underwriter's Warrant dated July 8, 1993 between the Registrant and
Hanifen, Imhoff Inc., filed as Exhibit 1.5 to Amendment No. 1 to
Registration Statement on Form S-1 filed with the Commission on
June 29, 1993, and incorporated herein by reference.
10.34 Custody Agreement - Selling Stockholders dated June 3, 1993 between
the Registrant, Double-Double Partners II, SDK Incorporated, James A.
McAuley, Carter G. Mathies, David L. Bradshaw and Society National
Bank, filed as Exhibit 1.6 to the initial Registration Statement on
Form S-1 filed with the Commission on June 4, 1993, and incorporated
herein by reference.
10.35 Warrant to Purchase the Registrant's common stock dated April 26,
1994, issued to Carter G. Mathies, filed as Exhibit 10.35 to Form 10-Q
dated March 31, 1994, 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.
10.38 Operating Agreement of Frisco City Fractionating, L.L.C. dated
August 19, 1994 among Flahive Oil & Gas LLC, O'Neal Resources
Corporation, Gunsmoke Gas Processing Company, Tipperary Corporation
and Milmac Operating Company filed as Exhibit 10.38 to Form 10-K dated
December 14, 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.
11.1 Calculation of per share earnings, filed herewith.
21.1 List of subsidiaries filed as Exhibit 21.1 to Form 10-K dated December
14, 1994, and incorporated herein by reference.
27 Financial Data Schedule, filed herewith.
</TABLE>
22
<PAGE>
TIPPERARY CORPORATION AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<S> <C>
Report of Independent Accountants F-2
Consolidated Balance Sheet
September 30, 1995 and 1994 F-3
Consolidated Statement of Operations
Years ended September 30, 1995, 1994 and 1993 F-4
Consolidated Statement of Stockholders' Equity
Years ended September 30, 1995, 1994 and 1993 F-6
Consolidated Statement of Cash Flows
Years ended September 30, 1995, 1994 and 1993 F-7
Notes to Consolidated Financial Statements F-9
</TABLE>
F-1
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders of Tipperary Corporation
In our opinion, the consolidated financial statements listed in the
accompanying index present fairly, in all material respects, the financial
position of Tipperary Corporation and its subsidiaries at September 30, 1995
and 1994, and the results of their operations and their cash flows for each
of the three years in the period ended September 30, 1995, 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/ Price Waterhouse LLP
PRICE WATERHOUSE LLP
Denver, Colorado
December 15, 1995
F-2
<PAGE>
TIPPERARY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
SEPTEMBER 30, 1995 AND 1994
(IN THOUSANDS)
<TABLE>
<CAPTION>
ASSETS 1995 1994
-------- --------
<S> <C> <C>
Current assets:
Cash and cash equivalents $ 4,193 $ 2,308
Receivables 2,355 3,339
Inventory 190 190
Current portion of deferred income taxes, net 21 209
Other current assets 176 388
-------- --------
Total current assets 6,935 6,434
-------- --------
Property, plant and equipment, at cost:
Oil and gas properties, full cost method 113,188 111,203
Other property and equipment 1,998 1,788
-------- --------
115,186 112,991
Less accumulated depreciation, depletion and amortization (81,527) (76,369)
-------- --------
Property, plant and equipment, net 33,659 36,622
-------- --------
Noncurrent portion of deferred income taxes, net 3,170 2,982
Investment in preferred stock 1,770 1,770
Investment in NGL fractionating plant 1,454 316
Other noncurrent assets 56 129
-------- --------
$ 47,044 $ 48,253
-------- --------
-------- --------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of long-term debt $ - $ -
Accounts payable 775 675
Accrued liabilities 194 219
Income taxes payable 42 -
Royalties payable 212 288
Production taxes payable 257 287
-------- --------
Total current liabilities 1,480 1,469
-------- --------
Long-term debt 15,746 15,746
Deferred lease obligation - 7
Commitments and contingencies (Note 8)
Stockholders' equity
Common stock; par value $.02; 20,000,000 shares
authorized; 11,237,404 issued and 11,209,604 outstanding
in 1995; 11,215,804 issued and 11,188,004 outstanding
in 1994 225 224
Capital in excess of par value 98,424 98,354
Accumulated deficit (68,760) (67,476)
Treasury stock, at cost; 27,800 shares (71) (71)
-------- --------
Total stockholders' equity 29,818 31,031
-------- --------
$ 47,044 $ 48,253
-------- --------
-------- --------
</TABLE>
See accompanying notes to consolidated financial statements.
F-3
<PAGE>
TIPPERARY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
YEARS ENDED SEPTEMBER 30, 1995, 1994 AND 1993
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
1995 1994 1993
------- ------- ------
<S> <C> <C> <C>
From continuing operations:
Revenues $11,837 $13,884 $9,499
Costs and expenses:
Operating 5,836 6,261 3,914
General and administrative 1,297 1,318 1,119
Depreciation, depletion and amortization 5,197 5,122 2,116
Write-down of oil and gas properties - 2,021 -
------- ------- ------
Total costs and expenses 12,330 14,722 7,149
------- ------- ------
Operating income (loss) (493) (838) 2,350
------- ------- ------
Other income (expense):
Interest income 160 53 187
Dividend income 89 18 -
Interest expense (976) (977) (262)
Research and development expense (40) (112) (233)
------- ------- ------
Total other expense (767) (1,018) (308)
------- ------- ------
Income (loss) from continuing operations
before income taxes (1,260) (1,856) 2,042
------- ------- ------
Current income tax benefit (expense) (24) 27 (734)
Deferred income tax benefit - 191 -
------- ------- ------
Income (loss) from continuing operations (1,284) (1,638) 1,308
------- ------- ------
From discontinued operations:
Income (loss) from discontinued gas
transmission operations, including
litigation proceeds (expenses) of ($210)
and $1,081 in 1994 and 1993, respectively,
net of income tax expense of $0 and $373
in 1994 and 1993, respectively - (214) 681
Loss on disposal of gas transmission
operations, net of income tax benefit of $4 - - (6)
------- ------- ------
Income (loss) before extraordinary items (1,284) (1,852) 1,983
------- ------- ------
</TABLE>
(Continued)
See accompanying notes to consolidated financial statements.
F-4
<PAGE>
TIPPERARY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS - CONTINUED
YEARS ENDED SEPTEMBER 30, 1995, 1994 AND 1993
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
1995 1994 1993
------- ------- ------
<S> <C> <C> <C>
Extraordinary items:
Loss on extinguishment of debt,
net of income tax benefit of $26 - - (49)
Tax benefit of net operating loss
carryforwards - - 930
------- ------- ------
Total extraordinary items - - 881
------- ------- ------
Income (loss) before cumulative effect of
change in method of accounting for
income taxes (1,284) (1,852) 2,864
Cumulative effect of change in method of
accounting for income taxes - 3,000 -
------- ------- ------
Net income (loss) $(1,284) $ 1,148 $2,864
------- ------- ------
------- ------- ------
Primary income (loss) per share:
From continuing operations $ (.11) $ (.15) $ .13
From discontinued operations $ - $ (.02) $ .07
From extraordinary items $ - $ - $ .09
------- ------- ------
Income before cumulative effect
of change in accounting principle (.11) (.17) .29
Cumulative effect of change in
accounting principle - .27 -
------- ------- ------
Net income (loss) $ (.11) $ .10 $ .29
------- ------- ------
------- ------- ------
Weighted average shares outstanding 11,190 11,311 9,982
------- ------- ------
------- ------- ------
</TABLE>
See accompanying notes to consolidated financial statements.
F-5
<PAGE>
TIPPERARY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
YEARS ENDED SEPTEMBER 30, 1995, 1994 AND 1993
(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, 1992 8,991 $ 180 $ 88,931 $ (71,488) - $ - $ 17,623
Net income - - - 2,864 - - 2,864
Common stock issuance 2,062 41 9,150 - - - 9,191
------ ------ --------- --------- ------ ------ --------
Balance September 30, 1993 11,053 221 98,081 (68,624) - - 29,678
Net income - - - 1,148 - - 1,148
Exercise of stock options and
warrants 163 3 266 - - - 269
Acquisition of treasury stock (28) - - - 28 (71) (71)
Tax benefit of non-qualified
stock option exercise - - 7 - - - 7
------ ------ --------- --------- ------ ------ --------
Balance September 30, 1994 11,188 224 98,354 (67,476) 28 (71) 31,031
Net loss - - - (1,284) - - (1,284)
Exercise of stock options and
warrants 22 1 59 - - - 60
Tax benefit of non-qualified
stock option exercise - - 11 - - - 11
------ ------ --------- --------- ------ ------ --------
Balance September 30, 1995 11,210 $ 225 $ 98,424 $ (68,760) 28 $ (71) $ 29,818
------ ------ --------- --------- ------ ------ --------
------ ------ --------- --------- ------ ------ --------
</TABLE>
See accompanying notes to consolidated financial statements.
F-6
<PAGE>
TIPPERARY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
YEARS ENDED SEPTEMBER 30, 1995, 1994 AND 1993
(IN THOUSANDS)
<TABLE>
<CAPTION>
1995 1994 1993
--------- -------- --------
<S> <C> <C> <C>
Cash flows from operating activities:
Net income $ (1,284) $ 1,148 $ 2,864
--------- -------- --------
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 5,197 5,122 2,116
Amortization of debt discount - - 6
Income tax effect of stock option exercise 11 7 -
Loss on extinguishment of debt - - 75
Deferred income tax benefit - (191) -
Cumulative effect of accounting change - (3,000) -
Write-down of oil and gas properties - 2,021 -
Deferred lease obligation and other (7) (10) (11)
Change in assets and liabilities, net of effects from
property acquisitions:
(Increase) decrease in receivables 984 (587) (1,118)
Decrease in oil and gas inventory - - 52
(Increase) decrease in other current assets 212 71 (12)
Increase (decrease) in accounts payable,
accrued liabilities and income taxes payable 117 (507) 251
Increase (decrease) in royalties payable (76) 218 60
Increase (decrease) in production taxes payable (30) 287 -
Other 34 (187) (85)
--------- -------- --------
Total adjustments 6,442 3,244 1,334
--------- -------- --------
Net cash provided by operating activities 5,158 4,392 4,198
--------- -------- --------
Cash flows from investing activities:
Proceeds from sale of assets 5,058 1,725 105
Investment in NGL fractionating plant (1,138) (316) -
Capital expenditures (7,253) (3,892) (31,724)
--------- -------- --------
Net cash used in investing activities (3,333) (2,483) (31,619)
--------- -------- --------
Cash flows from financing activities:
Proceeds from borrowing - - 15,650
Principal repayments - (1,950) (2,224)
Proceeds from issuance of stock 60 269 9,191
Acquisition of treasury stock - (71) -
--------- -------- --------
Net cash provided by (used in) financing
activities 60 (1,752) 22,617
--------- -------- --------
Net increase (decrease) in cash and cash equivalents 1,885 157 (4,804)
Cash and cash equivalents at beginning of year 2,308 2,151 6,955
--------- -------- --------
Cash and cash equivalents at end of year $ 4,193 $ 2,308 $ 2,151
--------- -------- --------
--------- -------- --------
</TABLE>
(Continued)
See accompanying notes to consolidated financial statements.
F-7
<PAGE>
TIPPERARY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS - CONTINUED
YEARS ENDED SEPTEMBER 30, 1995, 1994 AND 1993
(IN THOUSANDS)
<TABLE>
<CAPTION>
1995 1994 1993
--------- -------- --------
<S> <C> <C> <C>
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest $ 1,056 $ 1,003 $ 249
Income taxes $ - $ 41 $ 149
Supplemental disclosure of non-cash investing and
financing activities:
Sale of refinery property in exchange for
preferred stock (see Note 4) $ - $ 1,770 $ -
</TABLE>
See accompanying notes to consolidated financial statements.
F-8
<PAGE>
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
September 30, 1995, 1994 and 1993
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
CONSOLIDATION
The consolidated financial statements include the accounts of Tipperary
Corporation and its subsidiaries, all wholly owned (the "Company"). All
significant intercompany balances and transactions have been eliminated. The
Company's interest in certain investments is accounted for by the equity
method.
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 and other equity investments.
RECLASSIFICATION
Certain amounts reported herein for fiscal year 1994 have been reclassified
to correspond to the fiscal year 1995 presentation.
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 invests cash in bank money market accounts and other money
market funds which the Company believes have minimal risk of loss.
As an operator of jointly owned oil and gas properties, the Company sells oil
and gas production to numerous oil and gas purchasers and pays vendors for
oil and gas services. The risk of non-payment by the purchasers is
considered minimal, and the Company does not obtain collateral for sales to
them. Joint interest receivables are subject to collection under the terms
of operating agreements which provide lien rights, and the Company considers
the risk of loss likewise to be minimal.
FAIR VALUE OF FINANCIAL INSTRUMENTS
CASH AND SHORT-TERM INVESTMENTS
The carrying amount approximates fair value because of the short maturity of
these instruments.
INVESTMENT IN PREFERRED STOCK
The fair value of the preferred stock in United States Exploration, Inc.
("USXP") is estimated to be the carrying amount, or face amount of the stock.
This stock is not a publicly listed security and, therefore, no quoted market
prices are available. The convertible preferred stock was acquired on July
18, 1994 in exchange for the Company's Ingleside, Texas refinery property,
which had a recorded book value of $1,770,000. See Note 4. The stock was
valued based upon the estimated fair market value of the asset exchanged. The
preferred stock pays a dividend of 5% per annum in the form of cash or common
stock and is convertible into unregistered common stock based on a common
conversion price of $2.25 per share. The common stock of USXP is traded on
the Nasdaq small cap market under the symbol "USXP."
F-9
<PAGE>
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
INVENTORY
Inventory is composed of tubular goods and supplies and is valued at the
lower of average cost or market.
PROPERTY, PLANT AND EQUIPMENT
The Company follows the full cost method to account for its oil and gas
exploration and development activities. Under the full cost method, all costs
incurred which are directly related to oil and gas exploration and
development are capitalized and subjected to depreciation and depletion.
Depletable costs also include estimates of future development costs of proved
reserves. Costs related to undeveloped oil and gas properties may be
excluded from depletable costs until such properties are evaluated as either
proved or unproved. The net capitalized costs are subject to a ceiling
limitation. See Note 3. Gains or losses upon disposition of oil and gas
properties are treated as adjustments to capitalized costs, unless the
disposition represents a significant portion of the Company's proved
reserves. A separate cost center is maintained for expenditures applicable
to each country in which the Company conducts exploration and/or production
activities.
Repairs and maintenance are expensed; renewals and betterments are
capitalized. Certain indirect costs, including general and administrative
expense have been capitalized to property, plant and equipment.
Interest costs for the construction of certain long term assets and for the
investment in significant unproved properties and development projects are
capitalized and amortized over the related assets estimated useful life.
The Company capitalized $80,000 of interest costs in fiscal 1995.
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 of other property, plant and equipment is provided using the
straight-line method computed over estimated useful lives ranging from three
to fifteen years.
INCOME TAXES
In February 1992, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 109 ("SFAS 109"), "Accounting for
Income Taxes." SFAS 109 requires a change from the deferred method of
accounting for income taxes of APB Opinion No. 11, previously followed by the
Company, to an asset and liability approach. Previously the Company deferred
the tax effects of timing differences between financial reporting and taxable
income. Under the asset and liability method of SFAS 109, deferred tax
assets and liabilities are recognized for the expected future tax
consequences of temporary differences between the financial statement
carrying amounts and tax bases of existing assets and liabilities.
Measurement of current and deferred tax liabilities is based on provisions of
enacted tax law. The effects of future changes in tax laws or rates are not
known and therefore no
F-10
<PAGE>
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
provision is made for this uncertainty. The Company adopted SFAS 109 in the
first quarter of fiscal 1994, effective October 1, 1993.
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. Subsequent to
September 30, 1995, the Company hedged, under two swap agreements, 10,000
barrels per month (approximately 25%) of its oil production from December 1,
1995 through September 30, 1996 at an average floor price of $16.15 per
barrel. These hedging agreements allow the Company upside participation
percentages of 50% of price increases above the floor level. These hedge
prices are as quoted on the New York Mercantile Exchange ("NYMEX"). During
fiscal 1995, the Company hedged an average of 14,167 barrels (approximately
30%) of its oil production. The Company's actual price received at the
wellhead averaged $2.53 per barrel below NYMEX prices during fiscal 1995.
None of the Company's gas production was hedged during fiscal 1995 or is
currently hedged for periods subsequent to September 30, 1995. Net receipts
(payments) pursuant to the Company's hedging activities for fiscal 1995, 1994
and 1993 were $(183,000), $182,000 and $(14,000), respectively.
RESEARCH AND DEVELOPMENT EXPENSE
During the year ended September 30, 1993, the Company entered into an
agreement to provide funding for a research project being conducted at a
university. The project involves further development of a technology
designed to biodegrade absorbent materials utilized in the containment and
cleanup of oil spills and to release absorbed oil to the liquid phase. Costs
incurred pursuant to this agreement are expensed as incurred. The Company
paid $40,000, $112,000 and $233,000 pursuant to the agreement in fiscal 1995,
1994 and 1993, respectively.
EARNINGS (LOSS) PER SHARE
Primary earnings (loss) per share has been computed based on the weighted
average number of common and common equivalent shares outstanding during each
of the applicable periods using the treasury stock method. Effect has been
given to common stock warrants and options when their effect would be
dilutive.
SIGNIFICANT CUSTOMERS
The Company had sales in excess of 10% of total revenues to three
unaffiliated oil and gas customers during fiscal 1995 totaling 40%, two
unaffiliated oil and gas customers during fiscal 1994 totaling 22% and three
unaffiliated oil and gas customers during fiscal 1993 totaling 46%.
NOTE 2 - RELATED PARTY TRANSACTIONS
During fiscal 1993, the Company filed a registration statement with the
Securities and Exchange Commission, pursuant to which the Company,
Double-Double Partners II ("Double-Double") and two officers sold stock. The
Company and Double-Double entered into an agreement to bear expenses of the
offering proportionately. As of September 30, 1993, Double-Double owed the
Company $103,000 for its share of offering expenses, which sum was paid
during fiscal 1994. Double-Double, an investment partnership that was
liquidated during fiscal 1995, was a member of a related group owning
approximately 41.8% of the Company's common stock as of September 30, 1995.
During fiscal 1994, James A. McAuley, who serves on the Company's Board of
Directors, personally acquired an interest in a Utah limited liability
company of which the Company is also a member. The limited liability company
was formed for the purpose of constructing a natural gas liquids ("NGL")
fractionating plant in Alabama. Mr. McAuley negotiated and contracted
independently with third parties, as did the Company.
F-11
<PAGE>
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
NOTE 3 - OIL AND GAS FULL COST POOLS
UNITED STATES
The Company's domestic full cost pool includes costs incurred in domestic
property acquisitions and drilling costs. The total book value of the United
States full cost pool as of September 30, 1995 was $27,687,000. Included in
this total are $1,815,000 of acquisition costs attributable to nonproducing
oil and gas leases that have been excluded from depletable costs. 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 September 30, 1994 oil and gas prices, the Company's full cost pool book
value exceeded its ceiling test value by $2,021,000. Accordingly, the book
value of oil and gas properties was written down by this amount as of
September 30, 1994. Based on September 30, 1995 oil and gas prices, the
Company's ceiling test value exceeded its full cost pool book value.
At September 30, 1995, using prices in effect at such time and a discount
rate of 10% as prescribed by Securities and Exchange Commission rules, proved
oil and gas reserves decreased by 266,000 barrels and 2.6 Bcf, respectively,
from September 30, 1994 reserves calculated using prices in effect then. The
discounted future net revenues decreased from $29,021,000 as of September 30,
1994 (using prices as of that date) to $24,200,000 as of September 30, 1995.
The majority of the decrease in reserve volumes is attributable to the sale
of producing properties, discussed below, and to normal production without
replacement of the reserves. The decrease in discounted future net revenues
was attributable to these volume decreases, as well as to a lower oil price
at September 30, 1995 compared to September 30, 1994.
The Company sold its interest in certain gas properties and related assets in
La Plata County, Colorado for approximately $4,500,000 on May 1, 1995. The
Company sold its interest in other oil and gas properties in southern
Louisiana for approximately $600,000 on February 24, 1995. The two property
sales involved nonoperating working interests and represented approximately
5.4% of the Company's total discounted future net revenues and 486,000
barrels of oil equivalent ("BOE"), or 7.7% of the Company's total proved
reserve volumes as of September 30, 1994. Under the full cost method of
accounting, no gain or loss was recognized on the property sales; the
proceeds were credited to the full cost pool, thereby reducing the book
value of the Company's oil and gas properties.
On July 29, 1994, the Company acquired an undivided 87.5% working interest in
nonproducing oil and gas leases covering approximately 30,000 acres and has
subsequently leased approximately 15,000 additional acres in the same
vicinity. A 3-D seismic survey was conducted over approximately 30% of the
area, resulting in the identification of several drillable prospects. The
Company has permitted and staked well locations to test two of the prospects
and is currently considering conveying a portion of the project to third
parties for cash prior to drilling. If a suitable agreement is not reached
with a third party, the Company intends to begin drilling operations with its
existing 87.5% interest. As of September 30, 1995, the Company's investment
in the project totaled $1,815,000. This cost has been excluded from
depletable costs pending evaluation of the property.
AUSTRALIA
In April 1992, the Company acquired a nonoperating interest in the Comet
Ridge coalbed methane project in Queensland, Australia. The Company's
interest bears 30% of capital costs and 28.125% of operating expenses, and
its net revenue interest is 25.3125% prior to project payout. Subsequent to
project payout, the Company's interest bears 24% of capital and operating
expenses and its net revenue interest is 21.6%. The joint venture conducting
the project (the "Group") owns an Authority to Prospect ("ATP") covering
approximately 1,365,000 acres. The holder of the ATP may be granted
petroleum leases upon establishing to the satisfaction of the Queensland
government that commercial deposits of petroleum have been discovered.
Drilling operations commenced in November 1993, when one noncommercial well
was drilled on adjacent farmout acreage that has since been relinquished.
During fiscal 1994, two wells were drilled and, in fiscal 1995, an additional
14 wells were drilled in the Group's original ATP. Fourteen of the wells
located in the core Fairview area have been completed and are being
production tested. Most have been produced for several months for the
purpose of gathering data relative to gas and water production rates and
estimated
F-12
<PAGE>
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
recoverable gas reserves. Reservoir modeling, combined with evaluation of
actual production performance data, has allowed independent reservoir
engineers to assign technically recoverable reserve volumes to the 14 core
Fairview area wells. Although the Company has not included these reserves in
its proved reserves due to the lack of a sales contract and marketing
facilities, the Company believes the property is commercially productive.
The Company's Australia full cost pool includes costs incurred in the
original acquisition, drilling and completion costs, seismic and de-watering
costs. As of September 30, 1995, the capitalized cost applicable to the
Australia full cost pool was $5,125,000. All of the costs are unevaluated
and therefore not currently subject to depletion.
CHINA
The Company entered into a joint venture agreement with unrelated parties to
identify low cost exploration prospects for oil and gas reserves in mainland
China through April 30, 1995. The operator has conducted preliminary
operations necessary to develop and obtain land information and geological,
geophysical and other related data for the purpose of initiating and
conducting exploration and development projects. The Company has contributed
$38,000 to the joint venture pursuant to a maximum commitment of $102,000 and
will have the option to participate for up to 15% of the joint venture's
participation in any prospect. Management anticipates that the venture will
attempt to prospect for coalbed methane in mainland China, although no
projects have been initiated to date and the project is currently dormant.
As of September 30, 1995, the capitalized and unevaluated cost included in
the China full cost pool was $38,000.
NOTE 4 - OTHER INVESTMENTS
On July 18, 1994, the Company transferred its Ingleside, Texas refinery
property, with a recorded book value of $1,770,000, to United States
Exploration, Inc. ("USXP"), a public company traded on the Nasdaq small cap
market under the symbol "USXP", in exchange for $1,770,000 face amount of
convertible preferred stock in USXP. The preferred stock consists of two
series: 250,000 shares of Series A Convertible Preferred Stock, which may be
redeemed in cash at USXP's option prior to a conversion to common stock by
the Company; and 104,000 shares of Series B Convertible Preferred Stock,
which the Company may elect to convert into common stock of USXP
notwithstanding USXP's notification of its intent to redeem the issue for
cash. Both series of preferred shares pay a dividend of 5% per annum in the
form of cash or common stock of USXP, are nonvoting and are convertible into
common stock of USXP based upon a conversion price of $2.25 per share of
common stock. In connection with the foregoing transaction, the Company also
received the option to satisfy the outstanding debentures of USXP, totaling
$700,000 as of September 30, 1994, prior to their conversion into USXP common
stock. Subsequent to September 30, 1994, USXP retired $200,000 face amount,
leaving $500,000 outstanding. On June 15, 1995, the Company agreed to waive
its option to advance funds with respect to the remaining debentures in
connection with USXP's acquisition of oil and gas assets, whereby the sellers
acquired the debentures.
On August 19, 1994, the Company entered into an agreement with three other
parties to form a Utah limited liability company ("LLC") for the purpose of
constructing a natural gas liquids ("NGL") fractionating facility (the
"Plant") in Alabama. The LLC simultaneously entered into an agreement with
two other parties to form an Alabama limited liability company to construct
and operate the Plant. The Company committed to contribute $1,148,000 in
cash, in return for a 45% interest in Plant profits prior to payout of its
investment and a 27% interest thereafter. During fiscal 1995, the Company
agreed to increase its investment in connection with a restructuring of the
Plant ownership following certain cost overruns and construction delays. As
of September 30, 1995, the Company had invested $1,454,000 which investment
had increased to $1,939,000 subsequent to year end. The plant commenced
testing operations in November 1995 and is expected to commence full
production by calendar year end.
NOTE 5 - LONG-TERM DEBT
The Company's bank credit agreement provides a maximum facility of
$40,000,000, subject to borrowing base limitations described below. At the
Company's option, interest is payable at either the bank's Base Rate, or
London Interbank Offered Rate ("LIBOR") plus 1.5%. The LIBOR-based option
may be selected for periods not exceeding 90 days. At September 30, 1995, the
weighted average interest rate for amounts under the revolver was 7.66%. The
F-13
<PAGE>
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
agreement provides for a $10,000,000 fixed rate loan at 5.92%, with interest
payable monthly and principal due in full on September 30, 1996. The bank and
the Company have agreed that upon maturity of the fixed rate loan, it will
convert to a revolving loan pursuant to the current terms of the revolver.
The total outstanding loan balance at September 30, 1995 was $15,746,000;
$10,000,000 under the fixed rate loan and $5,746,000 under the LIBOR/Base
Rate loan. Upon the expiration of the revolver, the loan converts to a
four-year term loan on April 5, 1997. Certain of the Company's domestic oil
and gas properties have been pledged as security for the bank loan, and the
bank has the option to place additional liens on other unencumbered
properties. The 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 not agree with the Company's
assumptions. At September 30, 1995, the borrowing base remained at
$16,400,000, but was being reviewed by the bank; it is expected by management
to be reset at approximately $16,000,000 in January 1996. Should the
outstanding loan balance ever exceed the borrowing base, the Company is
required to either (i) make a cash payment to the bank equal to or greater
than such excess or (ii) provide additional collateral to the bank to
increase the borrowing base by the amount of the deficit. The Company is
obligated to pay a commitment fee of % per annum on the difference between
the average outstanding loan balance and the nominated borrowing base.
During fiscal 1995, the Company and the bank entered into an amendment to the
credit facility which extended the conversion of the revolving loan to a term
loan from April 5, 1996 to April 5, 1997. A fiscal 1994 amendment added a
provision which does not allow the Company to pay dividends without the prior
approval of the bank.
Scheduled maturities of long-term debt at September 30, 1995 are as follows:
fiscal 1997 - $1,968,000; fiscal 1998 - $3,937,000; fiscal 1999 - $3,937,000;
fiscal 2000 - $3,937,000; thereafter - $1,967,000.
NOTE 6 - STOCKHOLDERS' EQUITY
Stockholders' equity at September 30, 1995 and 1994 consisted of the
following (in thousands, except number of shares):
<TABLE>
<CAPTION>
1995 1994
--------- --------
<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; 11,237,404 issued and 11,209,604 outstanding
as of September 30, 1995; 11,215,804 issued and
11,188,004 outstanding as of September 30,1994 225 224
Capital in excess of par value 98,424 98,354
Accumulated deficit (68,760) (67,476)
Treasury stock, at cost; 27,800 shares (71) (71)
--------- --------
Total stockholders' equity $ 29,818 $ 31,031
--------- --------
--------- --------
</TABLE>
F-14
<PAGE>
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
PREFERRED STOCK
The Company's Board of Directors voted to cancel the designation of three
series of preferred stock on May 6, 1993. The two classes of preferred stock
reflected in the table above remain authorized under the Company's Articles
of Incorporation.
COMMON STOCK ISSUANCES
During fiscal 1993, the Company sold 2,012,500 shares of common stock in a
public offering at $4.625 per share, net of underwriting discounts and
commissions. It also issued 50,000 shares for consideration of $2.00 per
share pursuant to the exercise of warrants held by officers of the Company.
Net proceeds from these issuances were approximately $9,191,000. During
fiscal 1994, the Company issued 162,666 shares of common stock to former
officers and directors pursuant to the exercise of warrants and options;
112,666 shares were issued at $1.50 per share and 50,000 shares were issued
at $2.00 per share. Net proceeds to the Company were approximately $269,000.
During fiscal 1995, the Company issued 21,600 shares of common stock at
$2.75 per share to employees pursuant to the exercise of incentive stock
options. Net proceeds to the Company were approximately $60,000.
TREASURY STOCK
On May 13, 1994, the Company's Board of Directors approved the repurchase of
up to 100,000 shares of the Company's common stock on the open market.
During fiscal 1994, the Company acquired 27,800 shares at a total cost of
$71,000.
1987 EMPLOYEE STOCK OPTION PLAN
The Company established the 1987 Employee Stock Option Plan (the "Plan") in
order that options granted pursuant to the Plan would qualify as "incentive
stock options," as defined by the Internal Revenue Code of 1986. Options,
having a term of ten years, have been granted under the Plan to employees of
the Company for the purchase of common stock. The number of shares of common
stock which may be issued under the Plan was increased to 383,000 pursuant to
a shareholder vote on an amendment to the Plan. The Plan requires that the
exercise price must be equal to or greater than the fair market value of the
stock on the date of grant.
Incentive Stock Options granted under the Plan are as follows:
<TABLE>
<CAPTION>
EXERCISE PRICE
-------------------------------------------------
$2.75 $3.52 $3.69 $5.13 TOTAL
------- ----- ------ ------ -------
<S> <C> <C> <C> <C> <C>
As of September 30, 1992 - 1,250 - 1,250
Granted in fiscal 1993 - - 15,000 15,000
Forfeited in fiscal 1993 - - - -
Exercised in fiscal 1993 - - - -
------- ----- ------ ------ -------
As of September 30, 1993 - 1,250 - 15,000 16,250
------- ----- ------ ------ -------
Granted in fiscal 1994 251,000 - - - 251,000
Forfeited in fiscal 1994 (1,000) - - - (1,000)
Exercised in fiscal 1994 - - - - -
------- ----- ------ ------ -------
As of September 30, 1994 250,000 1,250 - 15,000 266,250
------- ----- ------ ------ -------
Granted in fiscal 1995 - - 15,000 - 15,000
Forfeited in fiscal 1995 - - - - -
Exercised in fiscal 1995 (21,600) - - - (21,600)
------- ----- ------ ------ -------
As of September 30, 1995 228,400(1) 1,250 15,000(1) 15,000(2) 259,650
------- ----- ------ ------ -------
------- ----- ------ ------ -------
Exercisable as of
September 30, 1995 61,733 1,250 - 6,000 68,983
------- ----- ------ ------ -------
------- ----- ------ ------ -------
</TABLE>
F-15
<PAGE>
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(1) Options vest ratably over three years. Included are options outstanding
for 100,000 shares held by Carter G. Mathies, Chief Executive Officer, and
80,000 shares held by David L. Bradshaw, Chief Operating Officer and
Chief Financial Officer, at an exercise price of $2.75 per share.
(2) Options vest ratably over five years.
NONQUALIFIED STOCK OPTIONS AND WARRANTS
Nonqualified warrant and option transactions for the three years ended
September 30, 1995 are as follows:
<TABLE>
<CAPTION>
Exercise Price
----------------------------------------------------------------------
$1.50 $2.00 $2.75 $6.00 $8.54 Total
-------- ------- ------- ------- ------- ---------
<S> <C> <C> <C> <C> <C> <C>
As of September 30, 1992 112,666 775,000 - - 241,442 1,129,108
Granted in fiscal 1993 - - - 100,000 - 100,000
Forfeited in fiscal 1993 - (50,000) - - - (50,000)
Exercised in fiscal 1993 - - - - - -
-------- ------- ------- ------- ------- ---------
As of September 30, 1993 112,666 725,000 - 100,000 241,442 1,179,108
-------- ------- ------- ------- ------- ---------
Granted in fiscal 1994 - - 100,000 - - 100,000
Expired in fiscal 1994 - - - - (241,442) (241,442)
Exercised in fiscal 1994 (112,666) (50,000) - - - (162,666)
-------- ------- ------- ------- ------- ---------
As of September 30, 1994 - 675,000 100,000 100,000 - 875,000
-------- ------- ------- ------- ------- ---------
Granted in fiscal 1995 - - - - - -
Expired in fiscal 1995 - - - - - -
Exercised in fiscal 1995 - - - - - -
-------- ------- ------- ------- ------- ---------
As of September 30, 1995 - 675,000(1) 100,000(2) 100,000(3) - 875,000
-------- ------- ------- ------- ------- ---------
-------- ------- ------- ------- ------- ---------
Exercisable as of
September 30, 1995 - 675,000 33,334 100,000 - 808,334
-------- ------- ------- ------- ------- ---------
-------- ------- ------- ------- ------- ---------
</TABLE>
(1) Includes warrants for 420,000 issued to Carter G. Mathies, Chief Executive
Officer, and 205,000 shares issued to David L. Bradshaw, Chief Operating
Officer and Chief Financial Officer, pursuant to employment contracts that
were executed effective October 1, 1990 and expired on September 30, 1995.
Also includes a warrant for 50,000 shares held by a Director.
(2) Effective January 25, 1994, the Company agreed to issue nonqualified
common stock warrants of 50,000 each to Eugene I. Davis, a Director, and
Carter G. Mathies, Chief Executive Officer. These warrants, which vest
ratably over three years, were issued on April 26, 1994.
(3) Warrant issued to Hanifen, Imhoff, Inc. pursuant to Underwriting
Agreement dated June 30, 1993. The warrant became exercisable on
June 30, 1994 and expires on June 30, 1996.
NOTE 7 - INCOME TAXES
The Company adopted SFAS 109 in the first quarter of fiscal 1994, effective
October 1, 1993. Because of the Company's significant net operating loss
("NOL") and other carryforwards, it recorded a deferred tax asset for the
carryforwards under SFAS 109. Since the Company's profitability is not
assured, a substantial valuation allowance was deducted from the value of the
asset. After valuation, the net deferred tax asset recorded on the October
1, 1993 balance sheet was $3,000,000. This amount was reflected in net
income as the cumulative effect of a change in method of accounting for
income taxes. The realization of this asset will have the effect of reducing
future earnings through a charge in lieu of income taxes. During the year
ended September 30, 1994, the Company also recognized a net benefit of
$191,000 due to adjustments to the net deferred tax asset. No deferred tax
expense or benefit was recognized during the fiscal year ended September 30,
1995. The Company will continue to review income trends and projected NOL
utilizations and will from time to time adjust the valuation allowance
accordingly.
F-16
<PAGE>
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Income tax expense (benefit) is different than the expected amount computed
using the applicable federal statutory income tax rates of 35% for 1995 and
1994 and 34% for 1993. The reasons for and effects of such differences (in
thousands) are as follows:
<TABLE>
<CAPTION>
1995 1994 1993
----- ----- ------
<S> <C> <C> <C>
Expected amount(1) $(441) $(724) $1,023
Increase (decrease) from:
Use of net operating loss carryforwards - - (930)
Increase in valuation allowance 846 546 -
Permanent differences between financial
statement income and taxable income (92) (13) (36)
Adjustments to prior years' income taxes
and carryforwards (305) (35) -
State taxes net of federal benefit, and other 16 8 90
----- ----- ------
Total income tax expense (benefit) $ 24 $(218) $ 147
----- ----- ------
----- ----- ------
</TABLE>
(1) Includes expected amounts due by applying the statutory tax rate to the
sum of income from continuing operations, income (loss) from and loss on
disposal of discontinued operations, and excludes cumulative effect of
accounting change.
The net deferred tax asset is comprised of the following at September 30,
1995 and 1994:
<TABLE>
<CAPTION>
1995 1994
-------- --------
<S> <C> <C>
Deferred tax assets:
Federal and state net operating loss carryforwards $ 16,028 $ 16,289
Statutory depletion carryforwards 2,815 2,708
Investment tax credit carryforwards 1,550 1,720
Property, plant and equipment 1,994 699
Other 226 351
-------- --------
Gross deferred tax assets 22,613 21,767
-------- --------
Valuation allowance (19,422) (18,576)
-------- --------
$ 3,191 $ 3,191
-------- --------
-------- --------
</TABLE>
The principal differences between recognition of taxable income (loss) for
federal income tax and financial reporting purposes relate to intangible
drilling costs, dry hole and abandonment costs, accelerated depreciation and
asset write-downs.
The Company has the following carryforwards (in thousands) at September 30,
1995:
<TABLE>
<CAPTION>
Federal Alternative
Income Tax Minimum Tax
---------- -----------
<S> <C> <C>
Net operating loss $ 43,619 $ 42,401
Investment tax credit $ 1,550 N/A
Statutory depletion $ 8,044 N/A
Minimum tax credit $ 224 N/A
</TABLE>
The net operating loss carryforwards expire at various dates from fiscal 1998
through fiscal 2009 (subject to certain limitations) and the investment tax
credit carryforwards are expiring currently. Statutory depletion and minimum
tax credit carryforwards do not expire.
F-17
<PAGE>
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
The Company's net operating loss carryforwards would be subjected to an
annual limitation should there be a change of over 50% in the stock ownership
of the Company during any three-year period after 1986. The Company is
required to report changes in ownership annually to the Internal Revenue
Service. As of September 30, 1995, no such ownership change had occurred.
NOTE 8 - COMMITMENTS AND CONTINGENCIES
On August 7, 1995, the operator of the Comet Ridge coalbed methane project in
Australia, Tri-Star Petroleum Company ("Tri-Star"), filed a declaratory
judgment action against the Company and another participant in the project
styled TRI-STAR PETROLEUM COMPANY V. AMERIND OIL COMPANY, LTD., AND TIPPERARY
OIL & GAS CORPORATION, Cause No. 40689, in the 238th Judicial District,
Midland County, Texas. The suit alleges that the Company and the other party
breached the existing operating agreement by failing to notify the operator
of their participation in, and make payment for, certain seismic operations.
The suit asks the Court to find that the alleged breach causes the Company
and the other party to forfeit all of their interest except for their
interest in existing wells. The Company has filed its original answer and
counterclaim denying the allegations and seeking declaratory judgment with
respect to several issues and injunctive relief prohibiting Tri-Star from
transferring or purporting to transfer the Company's interest in the project
to a third party. The Company believes the suit is without merit and is
vigorously defending its interest in the project. The Company does not
anticipate that this matter will have a material adverse effect on its
financial condition or results of operations.
The Company is a Defendant in a lawsuit filed on September 20, 1991 styled
VALERO TRANSMISSION, L.P. V. J. L. DAVIS V. TIPPERARY CORPORATION, Cause No.
91-09-00357-CVF, in the 81st Judicial District, Frio County, Texas. The case
involves gas purchase contracts between Valero and Davis. The Company
previously owned 50% of Davis' interest in the contracts. Valero claimed it
had overpaid Davis under the contracts and requested damages for breach of
contract from Davis. Davis thereafter filed a third-party petition against
the Company requesting that the Company reimburse Davis for 50% of any
amounts paid to Valero on account of the claims made by Valero in its
original petition. Valero and Davis have now settled the claims between
themselves, and Davis has requested that the Company reimburse Davis for 50%
of such settlement to the extent that the settlement covers time periods in
which Davis and the Company each owned a 50% interest in the contracts. The
Company has answered the lawsuit, denying the claims of Davis, and the
Company intends to vigorously defend all claims made in the suit. The Company
does not anticipate that this matter will have a material adverse effect on
its financial condition or results of operations.
On August 19, 1994, the Company entered into an agreement with three other
parties to form a Utah limited liability company ("LLC") for the purpose of
constructing a natural gas liquids ("NGL") fractionating facility (the Plant)
in Alabama. The LLC simultaneously entered into an agreement with two
other parties to form an Alabama limited liability company to construct and
operate the Plant. The Company committed to contribute $1,148,000 in cash in
return for a 45% interest in Plant profits prior to payout of its investment
and a 27% interest thereafter. During fiscal 1995, the Company agreed to
increase its investment in connection with a restructuring of the Plant
ownership following certain cost overruns and construction delays. As of
September 30, 1995, the Company had invested $1,454,000 which investment
increased to $1,939,000 subsequent to year end. The plant is substantially
complete and is expected to begin full operation in December 1995. The
Company is not obligated to incur further material capital investment beyond
the $1,939,000, but may elect to increase its investment in return for
additional interest in the Plant. Subsequent to the aforementioned
restructuring, the Company expects to own an interest in the Plant of between
50% and 55% prior to payout and an interest of between 37% and 47% thereafter.
The Company entered into an amendment to its office lease agreement in
Denver, Colorado effective September 1, 1993. The amended lease covers
11,000 square feet for a term of five years. The Company has a one-time
right to terminate the lease at the end of the third year. During the term
of the lease, rent is payable in the amount of $116,000 base rent per year,
plus expense recovery amounts. During the fiscal years ended September 30,
1995, 1994 and 1993, the Company paid approximately $116,000, $119,000 and
$78,000, respectively, in office rent.
The Company is subject to various possible contingencies which arise
primarily from interpretation of federal and state laws and regulations
affecting the oil and gas industry. Although management believes it has
complied with the various laws and regulations, administrative rulings and
interpretations thereof, adjustment could be required as new interpretations
and regulations are issued.
F-18
<PAGE>
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
NOTE 9 - DISCONTINUED OPERATIONS
The Company and a former employee of its discontinued gas transmission
business settled litigation related to an employment agreement on December
31, 1993. The Company's payment of $210,000 pursuant to this settlement and
other minor income and expenses attributable to this business are reported in
the financial statements under Discontinued Operations.
On July 18, 1994, the Company transferred its Ingleside, Texas refinery
property, with a recorded book value of $1,770,000, to United States
Exploration, Inc. ("USXP"), a public company traded on the Nasdaq small cap
market under the symbol "USXP", in exchange for $1,770,000 face amount of
convertible preferred stock in USXP. The Company's refining operations were
discontinued in 1984, after which time the refinery had been carried as an
"asset held for resale." See Note 4.
F-19
<PAGE>
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
NOTE 10 - 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 1995, 1994 and 1993 (in
thousands) are as follows:
<TABLE>
<CAPTION>
1995 1994 1993
-------- -------- --------
<S> <C> <C> <C>
Capitalized costs:
Proved properties:
United States $100,082 $103,375 $105,037
Unproved properties:
United States 7,943 6,977 6,059
Australia 5,125 813 167
China 38 38 25
-------- -------- --------
Total unproved properties 13,106 7,828 6,251
-------- -------- --------
Total proved and unproved 113,188 111,203 111,288
-------- -------- --------
Less accumulated depletion:
United States (80,338) (75,306) (70,289)
-------- -------- --------
Total $ 32,850 $ 35,897 $ 40,999
-------- -------- --------
-------- -------- --------
Costs incurred:
Property acquisition costs:
Proved properties:
United States $ 207 $ 323 $ 26,557
Unproved properties:
United States 992 920 3,342
Australia 300 187 56
China - 13 25
-------- -------- --------
1,292 1,120 3,423
-------- -------- --------
Exploration costs:
United States 330 - 143
Australia 133 459 -
-------- -------- --------
463 459 143
-------- -------- --------
Development costs:
United States 1,202 1,760 1,048
Australia 3,879 - -
-------- -------- --------
5,081 1,760 1,048
-------- -------- --------
Total costs incurred $ 7,043 $ 3,662 $ 31,171
-------- -------- --------
-------- -------- --------
</TABLE>
Depletion rates per equivalent barrel of production for the years ended
September 30, 1995, 1994 and 1993 were $5.54, $4.72 and $3.39, respectively.
Costs of $1,815 and $1,008 related to unproved oil and gas properties were
excluded from depletable costs in fiscal 1995 and fiscal 1994, respectively.
There were no costs excluded in fiscal 1993.
F-20
<PAGE>
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
The results of operations for petroleum producing activities, excluding
corporate overhead and interest costs, for each of the three years in the
period ended September 30, 1995 (in thousands) are as follows:
<TABLE>
<CAPTION>
1995 1994 1993
------- ------- -------
<S> <C> <C> <C>
Revenue from sale of oil and gas $11,673 $13,623 $ 9,153
Production costs (5,726) (6,210) (3,961)
Depreciation, depletion and amortization
including impairment (5,032) (7,038) (2,058)
Income tax expense (18) (17) (152)
------- ------- -------
Results of operations $ 897 $ 358 $ 2,982
------- ------- -------
------- ------- -------
</TABLE>
Revenues of $164, $261 and $346 were not included above for 1995, 1994 and
1993, respectively, which represent revenues received primarily for saltwater
disposal. Production costs of $144, $153 and $156 were included above for
1995, 1994 1993, respectively, which represent costs paid or payable to other
affiliates in the consolidated group. Costs associated with the saltwater
disposal revenue and other costs of $ 254, $204 and $109 were not included
above for 1995, 1994 and 1993, respectively. Income tax expense is computed
using the Company's overall effective tax rate for each respective year,
including extraordinary tax benefit from the Company's net operating loss
carryforwards for 1993.
The following tables set forth information (in thousands) for fiscal 1995,
1994 and 1993 with respect to changes in the Company's proved reserves (all
of which are in the United States) as estimated by several independent
petroleum engineers, predominantly Heinle & Associates, Inc. and Forrest A.
Garb & Associates, Inc.
<TABLE>
<CAPTION>
1995 1994 1993
-------------- --------------- ---------------
Oil Gas Oil Gas Oil Gas
Bbls MCF Bbls MCF Bbls MCF
----- ------ ----- ------ ----- -----
<S> <C> <C> <C> <C> <C> <C>
Total proved reserves:
Beginning of year 3,685 15,645 5,532 26,852 2,320 9,940
Revisions of previous estimates (31) 1,361 (860) (8,437) 157 (196)
Extensions, discoveries
and other additions 343 723 3 126 99 230
Purchases of reserves in place 24 15 73 134 3,337 18,293
Sale of reserves in place (37) (2,622) (417) (530) (2) (48)
Production (565) (2,061) (646) (2,500) (379) (1,367)
----- ------ ----- ------ ----- ------
End of year 3,419 13,061 3,685 15,645 5,532 26,852
----- ------ ----- ------ ----- ------
----- ------ ----- ------ ----- ------
Proved developed reserves:
Beginning of year 3,423 13,839 4,952 20,448 1,984 8,449
----- ------ ----- ------ ----- ------
----- ------ ----- ------ ----- ------
End of year 2,952 10,798 3,423 13,839 4,952 20,448
----- ------ ----- ------ ----- ------
----- ------ ----- ------ ----- ------
</TABLE>
F-21
<PAGE>
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Information with respect to the Company s estimated discounted future cash
flows from its oil and gas properties for fiscal 1995, 1994 and 1993 (in
thousands) follows:
<TABLE>
<CAPTION>
1995 1994 1993
-------- -------- --------
<S> <C> <C> <C>
Future cash flows $ 74,482 $ 82,985 $144,281
Future production costs (33,026) (35,850) (57,471)
Future development costs (2,840) (1,667) (1,901)
Future income tax expense (431) (561) (2,389)
-------- -------- --------
Future net cash flows 38,185 44,907 82,520
10% annual discount (13,985) (15,886) (32,893)
-------- -------- --------
Discounted future net cash flows $ 24,200 $ 29,021 $ 49,627
-------- -------- --------
-------- -------- --------
</TABLE>
Principal changes in the Company's estimated discounted future net cash flows
for each of the three years in the period ended September 30, 1995 (in
thousands) are as follows:
<TABLE>
<CAPTION>
1995 1994 1993
-------- -------- --------
<S> <C> <C> <C>
Beginning of year $ 29,021 $ 49,627 $ 23,242
Oil and gas sales, net of production costs (6,091) (7,565) (5,347)
Net change in prices and production costs (440) (4,003) (3,261)
Extensions and discoveries less related cost 1,274 67 802
Purchases of reserves in place, net 99 469 33,796
Sales of reserves in place, net (1,581) (1,968) (40)
Change in estimated development costs (1,117) 348 (1,081)
Revision of previous quantity estimates 906 (11,237) 727
Accretion of discount 2,902 4,963 2,324
Net change in income taxes 56 1,072 (946)
Changes in production rates and other (829) (2,752) (589)
-------- -------- --------
End of year $ 24,200 $ 29,021 $ 49,627
-------- -------- --------
-------- -------- --------
</TABLE>
At September 30, 1995, average oil and gas prices used in the determination
of future cash flows were $15.45 and $1.64, respectively.
During the fiscal year ended September 30, 1995, a report was filed with the
U.S. Department of Energy reflecting oil and gas reserves for certain of the
Company's properties. Reserve figures submitted were the same as those
included in the tables above.
F-22
<PAGE>
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
NOTE 11 - QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
The following is a summary of the unaudited quarterly results of operations
for the fiscal years ended September 30, 1995 and 1994 (in thousands, except
per share data).
<TABLE>
<CAPTION>
Quarter Ended
---------------------------------------------
12/31/94 3/31/95 6/30/95 9/30/95
-------- ------- ------- -------
September 30, 1995 Total
- ------------------ -----
<S> <C> <C> <C> <C> <C>
Revenues $ 2,941 $3,163 $3,132 $ 2,601 $11,837
------- ------ ------ ------- -------
------- ------ ------ ------- -------
Gross profit $ 1,567 $1,712 $1,664 $ 1,058 $ 6,001
------- ------ ------ ------- -------
------- ------ ------ ------- -------
Net loss $ (431) $ (293) $ (143) $ (417) $(1,284)
------- ------ ------ ------- -------
------- ------ ------ ------- -------
Net loss per common share $(0.04) $(0.02) $(0.01) $ (0.04) $ (0.11)
------- ------ ------ ------- -------
------- ------ ------ ------- -------
</TABLE>
<TABLE>
<CAPTION>
Quarter Ended
---------------------------------------------
12/31/93 3/31/94 6/30/94 9/30/94
-------- ------- ------- -------
September 30, 1994 Total
- ------------------ -----
<S> <C> <C> <C> <C> <C>
Revenues $ 3,741 $3,466 $3,490 $ 3,187 $13,884
------- ------ ------ ------- -------
------- ------ ------ ------- -------
Gross profit $ 2,272 $1,808 $2,009 $ 1,534 $ 7,623
------- ------ ------ ------- -------
------- ------ ------ ------- -------
Income (loss) before cumulative
effect of accounting change $ 233 $ 148 $ 321 $(2,554) $(1,852)
------- ------ ------ ------- -------
------- ------ ------ ------- -------
Income (loss) before cumulative effect of
accounting change per common share $ 0.02 $ 0.01 $ 0.03 $ (.21) $ (.15)
------- ------ ------ ------- -------
------- ------ ------ ------- -------
Net income (loss) $ 3,233 $ 148 $ 321 $(2,554) $ 1,148
------- ------ ------ ------- -------
------- ------ ------ ------- -------
Net income (loss) per common share $ .28 $ .01 $ .03 $ (.22) $ .10
------- ------ ------ ------- -------
------- ------ ------ ------- -------
</TABLE>
F-23
<PAGE>
TIPPERARY CORPORATION AND SUBSIDIARIES
Calculation of Weighted Average Number of Shares Outstanding
Years Ended September 30, 1993, 1994 and 1995
(in thousands)
<TABLE>
<CAPTION>
Description of Transaction Number Weighting Weighted
of Shares Factor Average
--------- --------- --------
<S> <C> <C> <C>
Year ended Spetember 30, 1993:
Primary Shares
Beginning of period 8,990 365/365 8,990
Shares issued on secondary offering 2,063 84/365 475
Common stock equivalents(1) 523 350/365 517
------ ------
End of period 11,576 9,982
------ ------
------ ------
Year ended September 30, 1994:
Primary Shares
Beginning of period 11,053 365/365 11,053
Shares repurchased (28) 117/365 (9)
Shares issued upon exercise of
options and warrants 163 4/365 2
Common stock equivalents(1) 265 365/365 265
------ ------
End of period 11,453 11,311
------ ------
------ ------
Year ended September 30, 1995:
Primary Shares
Beginning of period 11,188 365/365 11,188
Shares issued upon exercise of
options and warrants 22 35/365 2
Common stock equivalents(1) 467 N/A 0
------ ------
End of period 11,677 11,190
------ ------
------ ------
</TABLE>
(1) Dilution less than 3%.
(2) Antidilutive.
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED BALANCE SHEET AND CONSOLIDATED STATEMENT OF OPERATIONS FOUND ON
PAGES F-3, F-4 AND F-5 OF THE COMPANY'S FORM 10-K FOR THE YEAR ENDED SEPTEMBER
30, 1995 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> SEP-30-1995
<PERIOD-START> OCT-01-1994
<PERIOD-END> SEP-30-1995
<CASH> 4,193
<SECURITIES> 0
<RECEIVABLES> 2,355
<ALLOWANCES> 0
<INVENTORY> 190
<CURRENT-ASSETS> 6,935
<PP&E> 115,186
<DEPRECIATION> 81,527
<TOTAL-ASSETS> 47,044
<CURRENT-LIABILITIES> 1,480
<BONDS> 15,746
<COMMON> 225
0
0
<OTHER-SE> 29,593
<TOTAL-LIABILITY-AND-EQUITY> 47,044
<SALES> 11,837
<TOTAL-REVENUES> 11,837
<CGS> 5,836
<TOTAL-COSTS> 12,330
<OTHER-EXPENSES> 209
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 976
<INCOME-PRETAX> (1,260)
<INCOME-TAX> 24
<INCOME-CONTINUING> (1,284)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (1,284)
<EPS-PRIMARY> (.11)
<EPS-DILUTED> (.11)
</TABLE>
