UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
- ------ EXCHANGE ACT OF 1934
For the quarterly period ended December 31, 1996
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OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
- ------ EXCHANGE ACT OF 1934
For the transition period from to
-------------- ---------------
Commission File Number 1-7796
TIPPERARY CORPORATION
(Exact name of registrant as specified in its charter)
Texas 75-1236955
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
633 Seventeenth Street, Suite 1550
Denver, Colorado 80202
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (303) 293-9379
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
------- -------
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Class Outstanding February 13, 1997
- ---------------------------- -----------------------------
Common Stock, $.02 par value 13,050,271 shares
TIPPERARY CORPORATION AND SUBSIDIARIES
Index to Form 10-Q
Page No.
PART I. FINANCIAL INFORMATION (UNAUDITED)
Item 1. Financial Statements
Consolidated Balance Sheet
December 31, 1996 and September 30, 1996 1
Consolidated Statement of Operations
Three months ended December 31, 1996 and 1995 2
Consolidated Statement of Cash Flows
Three months ended December 31, 1996 and 1995 3
Notes to Consolidated Financial Statements 4
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations 5
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 10
Item 2. Changes in Securities 10
Item 3. Defaults Upon Senior Securities 10
Item 4. Submission of Matters to a Vote of Security
Holders 10
Item 5. Other Information 10
Item 6. Exhibits and Reports on Form 8-K 10
SIGNATURES 11
PART I - FINANCIAL INFORMATION
------------------------------
Item 1. Financial Statements
TIPPERARY CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheet
(in thousands)
(unaudited)
December 31, September 30,
1996 1996
------------ -------------
ASSETS
Current assets:
Cash and cash equivalents $ 3,067 $ 3,575
Receivables 2,493 2,154
Inventory 190 190
Current portion of deferred income taxes, net 75 57
Other current assets 162 123
------------ -------------
Total current assets 5,987 6,099
------------ -------------
Property, plant and equipment, at cost:
Oil and gas properties, full cost method 123,593 122,360
Other property and equipment 2,343 2,336
------------ -------------
125,936 124,696
Less accumulated depreciation, depletion and
amortization (86,150) (85,215)
------------ -------------
Property, plant and equipment, net 39,786 39,481
------------ -------------
Noncurrent portion of deferred income taxes, net 3,116 3,134
Investment in NGL fractionating plant 2,431 2,474
Investment in stock 897 707
Other noncurrent assets 14 203
------------ -------------
$ 52,231 $ 52,098
============ =============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of long-term debt $ - $ -
Accounts payable 660 1,539
Accrued liabilities 234 215
Production taxes payable 187 186
Royalties payable 139 148
Income taxes payable 11 -
------------ -------------
Total current liabilities 1,231 2,088
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Long-term debt 13,994 13,994
Commitments and contingencies (Note 2)
Stockholders' equity
Common stock; par value $.02; 20,000,000
shares authorized; 13,078,071 issued
and 13,050,271 outstanding 262 262
Capital in excess of par value 105,387 105,375
Accumulated deficit (68,572) (69,550)
Treasury stock, at cost; 27,800 shares (71) (71)
------------ -------------
Total stockholders' equity 37,006 36,016
------------ -------------
$ 52,231 $ 52,098
============ =============
See accompanying notes to consolidated financial statements.
1
TIPPERARY CORPORATION AND SUBSIDIARIES
Consolidated Statement of Operations
(in thousands, except per share data)
(unaudited)
Three months ended
December 31,
------------------
1996 1995
-------- --------
Revenues $ 4,112 $ 2,631
Costs and expenses:
Operating 1,470 1,298
General and administrative 437 349
Depreciation, depletion and amortization 935 1,028
-------- --------
Total costs and expenses 2,842 2,675
-------- --------
Operating income (loss) 1,270 (44)
Other income (expense):
Interest income 29 68
Dividend income - 22
Interest expense (245) (256)
-------- --------
Total other expense (216) (166)
-------- --------
Income (loss) before income tax 1,054 (210)
Current income tax expense (23) (3)
-------- --------
Income (loss) before equity in loss of NGL
fractionating plant 1,031 (213)
Equity in loss of NGL fractionating plant (53) (28)
-------- --------
Net income (loss) $ 978 $ (241)
======== ========
Net income (loss) per share $ .07 $ (.02)
======== ========
Weighted average shares outstanding 13,050 11,210
======== ========
See accompanying notes to consolidated financial statements.
2
TIPPERARY CORPORATION AND SUBSIDIARIES
Consolidated Statement of Cash Flows
(in thousands)
(unaudited)
Three months ended
December 31,
------------------
1996 1995
-------- --------
Cash flows from operating activities:
Net income (loss) $ 978 $ (241)
Adjustments to reconcile net income (loss) to net
cash provided by operating activities:
Depreciation, depletion and amortization 935 1,028
Equity in loss of NGL fractionating plant 53 28
Tax effect of stock option exercise 12 -
Change in assets and liabilities:
(Increase) decrease in receivables (339) 295
Increase in other current assets (39) (55)
Decrease in accounts payable, accrued
liabilities, and production and income
taxes payable (848) (244)
Decrease in royalties payable (9) (47)
Other (1) 1
-------- --------
Net cash provided by operating activities 742 765
-------- --------
Cash flows from investing activities:
Proceeds from asset sales 12 56
Investment in NGL fractionating plant (10) (653)
Capital expenditures (1,252) (640)
-------- --------
Net cash used in investing activities (1,250) (1,237)
Net decrease in cash and cash equivalents (508) (472)
Cash and cash equivalents at beginning of period 3,575 4,193
-------- --------
Cash and cash equivalents at end of period $ 3,067 $ 3,721
======== ========
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest $ 182 $ 255
Income taxes $ - $ 3
See accompanying notes to consolidated financial statements.
3
TIPPERARY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(unaudited)
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PRESENTATION
In the opinion of management, the accompanying unaudited financial statements
reflect all adjustments, consisting only of normal recurring adjustments, which
are necessary for a fair presentation of the consolidated financial position of
Tipperary Corporation (the "Company") at December 31, 1996, and the results of
its operations for the three-month periods ended December 31, 1996, and 1995.
The consolidated financial statements include the accounts of Tipperary
Corporation and its subsidiaries, all wholly-owned, and its share of assets,
liabilities, revenues and expenses of unincorporated joint ventures and
partnerships. The accounting policies followed by the Company are included in
Note 1 to the Consolidated Financial Statements in the Annual Report on Form
10-K for the year ended September 30, 1996. These financial statements should
be read in conjunction with the Form 10-K.
IMPACT OF NEW ACCOUNTING PRONOUNCEMENTS
The Company adopted Statement of Financial Accounting Standards No. 121,
"Accounting for the Impairment of Long-lived Assets and for Long-lived Assets to
Be Disposed Of" ("SFAS 121", effective October 1, 1996. SFAS 121 requires the
write-down to market value of certain long-lived assets and applies to the
Company's long-lived assets other than oil and gas properties, which will
continue to be accounted for using the full cost method. The adoption of SFAS
121 had no impact on the Company's financial condition or results of operations
for the quarter ended December 31, 1996.
The Company adopted Statement of Financial Accounting Standards No. 123,
"Accounting for Stock-Based Compensation" ("SFAS 123"), effective October 1,
1996. As permitted under SFAS 123, the Company elected to continue to measure
compensation cost using the intrinsic value based method of accounting
prescribed by APB Opinion No. 25, "Accounting for Stock Issued to Employees,"
and to make pro forma disclosures of net income as if the fair value based
method of accounting as defined in SFAS 123 had been applied. In October 1996,
the Company granted certain employees options to purchase 85,000 shares of its
common stock at $3.63 per share. The Company will make the required pro forma
disclosures in the notes to its annual financial statements.
NOTE 2 - COMMITMENTS AND CONTINGENCIES
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 October 7, 1996, the Company filed a Motion to Intervene as a plaintiff in
the proceeding APACHE OIL CORPORATION AND SNYDER OIL CORPORATION V. MDU
RESOURCES GROUP, INC., AND WILLISTON BASIN INTERSTATE PIPELINE COMPANY,
INC., in the District Court, McKenzie County, North Dakota. The case involves
the production and sale of natural gas by the Company's predecessors in the
McKenzie Gas Processing Plant in North Dakota. The Company claims that its
predecessors sold gas through a contract to the defendants, and defendants
breached those contracts. The Company believes that it is entitled to receive
part of the resulting damages. The Company is among a group of gas producers
that filed the Motion to Intervene. The Motion was denied, but the Company
anticipates joining the other producers and filing a new action against the
defendants.
4
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
FINANCIAL CONDITION
During the three months ended December 31, 1996, the Company continued its
exploration efforts in the Comet Ridge coalbed methane project in Queensland,
Australia, the Missouri River project in Montana and the Divide project in North
Dakota. The Company also continued development drilling on its existing
properties. During the quarter, the Company incurred capital expenditures of
$1,252,000, received proceeds of $12,000 from miscellaneous oil and gas property
sales and invested an additional $10,000 in the Alabama natural gas liquids
("NGL") fractionating plant, resulting in net cash used in investing activities
of $1,250,000. The capital expenditures included an investment of $527,000 for
the Company's share of cash advances for initial costs to drill three wells in
the Comet Ridge project, approximately $521,000 in domestic development drilling
costs, and $204,000 in other capital expenditures, of which $70,000 was for
leasehold acquisitions. During the quarter ended December 31, 1995, the Company
incurred $640,000 in capital expenditures, invested $653,000 in the construction
of the NGL fractionating plant, and received proceeds of $56,000 from the sale
of producing oil and gas properties, resulting in net cash used in investing
activities of $1,237,000. The capital expenditures of $640,000 were incurred
primarily in domestic oil and gas operations.
The Company had cash and temporary investments of $3,067,000 as of December 31,
1996, versus $3,575,000 as of September 30, 1996. Cash flows were provided
primarily by the Company's producing oil and gas properties during both the
three months ended December 31, 1996 and 1995. Net cash provided by operating
activities was $742,000 and $765,000 for the fiscal 1997 and fiscal 1996
quarters, respectively. Receivables increased $339,000 to $2,493,000 at
December 31, 1996 from $2,154,000 at September 30, 1996 due to accruals of
revenue at higher oil and gas prices. The decrease in accounts payable of
$879,000 to $660,000 at December 31, 1996 from $1,539,000 at September 30, 1996
was due to payment of certain drilling costs on the Comet Ridge project and to
the timing of payment of other accounts payable. The Company made no principal
payments in either period on its long term debt, all of which was owed to the
Company's commercial bank lender. Principal payments totaling $1,752,000 were
made during fiscal 1996 and the Company made an additional $150,000 principal
payment in January 1997.
While the Company's cash flows are directly affected by oil and gas prices, the
Company's existing hedge positions partially mitigate the effects of lower
prices. The Company presently has hedged, under "swap" and put option
agreements, an average of 20,000 barrels per month, or approximately 50%, of its
remaining fiscal 1997 monthly oil production subsequent to December 31, 1996.
An average of 16,667 barrels is hedged through swap agreements with a weighted
average floor price of $19.09 per barrel. An average of 3,333 barrels per month
is hedged through put option agreements with a strike price of $20.00 per
barrel. The swap agreements provide the Company with 50% participation in
actual prices in excess of the floor level. The Company's actual price received
for oil at the wellhead during the first quarter of fiscal 1997 averaged $2.12
per barrel below the average New York Mercantile Exchange ("NYMEX") price. This
difference varies based on location and quality of oil sold.
Subsequent to December 31, 1996, the Company entered into an agreement to hedge
an average of approximately 8,000 MMBtu per month, or approximately 7%, of its
remaining fiscal 1997 monthly natural gas production subsequent to December 31,
1996, through a put option with a strike price of $2.20 per MMBtu. The
Company's actual price received for gas during the first quarter of fiscal 1997
averaged $1.01 below the average NYMEX price. The difference between the
average NYMEX price and price received for gas by the Company varies based on
location, liquid content and type of contract. Notwithstanding the Company's
hedging positions, decreases in oil and gas prices subsequent to December 31,
1996, could cause a significant reduction in cash flows available for the
funding of capital projects and reduction of bank debt and could negatively
impact the Company's efforts to secure new financing.
The Company's bank credit agreement (the "Agreement") provides a maximum loan
facility of $40,000,000 subject to borrowing base limitations described below.
The Agreement contains provisions for both fixed rate and variable rate
borrowings. At the Company's option, interest on the revolver is payable at
either the London Interbank Offered Rate ("LIBOR") plus 1.5% or the bank's Base
Rate. The LIBOR-based option may be selected for periods not exceeding 90 days.
At December 31, 1996, the Company's outstanding debt of $13,994,000 carried a
weighted average interest rate of 7.06%. Upon expiration of the revolver (the
"Conversion Date"), the principal balance will convert to a four-year term loan.
The Conversion Date was recently extended by the bank from October 5, 1997, to
October 5, 1998.
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 maximum borrowing base is
determined
5
solely by the bank and is based upon its assessment of the value of the
Company's properties. This bank valuation is based upon the bank's assumptions
about reserve quantities, oil and gas prices, operating expenses and other
assumptions, all of which may change from time to time and which may differ from
the Company's assumptions. In February 1997, the borrowing base was reduced to
$14,500,000. Should the outstanding loan balance ever exceed the borrowing
base, the Company is required to either make a cash payment to the bank equal to
or greater than such excess or provide additional collateral to the bank to
increase the borrowing base by the amount of the deficit. In the event oil
prices or natural gas prices decline by a significant amount, the Company's
borrowing base could be reduced to an amount less than the loan balance,
resulting in the Company having to fulfill the foregoing requirements. 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 borrowing base. The
agreement provides that the Company may not pay dividends or incur additional
debt without prior approval from the bank.
The Company has minimal remaining unused borrowing capacity, and is therefore
attempting to establish additional oil and gas reserves through its exploitation
and exploration projects, which if successful, could increase its borrowing base
with the bank. 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's capital investment has been directed primarily to the following
projects:
INTERNATIONAL EXPLORATION AND DEVELOPMENT
In April 1992, the Company acquired a non-operating interest in the Comet Ridge
coalbed methane project in the Bowen Basin located in Queensland, Australia. As
of September 30, 1996, the co-venturers conducting the project (the "Group")
held an Authority to Prospect ("ATP") granted by the Queensland government
covering approximately 1,365,000 acres. The holder of an ATP may be granted
petroleum leases upon establishing to the satisfaction of the Queensland
government that commercial deposits of petroleum have been discovered. During
fiscal 1996, the Group was granted petroleum leases covering approximately
167,000 acres in the area known as "Fairview," which is in the southern portion
of the ATP. In October 1996, the Group filed for a four-year renewal and
relinquished approximately 20% of its acreage along the western border of the
ATP, which it considers to be of only marginal interest. The ATP was renewed
effective November 1, 1996, for a four-year period. The Group's renewed ATP
covers approximately 1,088,000 acres, of which 167,000 acres are already covered
by the petroleum leases. The new ATP requires certain minimum expenditures,
based on current exchange rates, of approximately $237,000 in year one, $428,000
in years two and three, and $765,000 in year four. The Company will be
responsible for its pro rata share of these expenditures.
As of December 31, 1996, the Group had drilled 17 wells on its ATP acreage, of
which 16 are in the Fairview area and one well is awaiting completion in the
Dawson area in the northern portion of the ATP. Fourteen of the wells are in a
core area where significant de-watering and production testing has been done,
with natural gas being flared. Based upon past production testing, continued
de-watering is expected to further increase gas production rates. In December
1996, the Group abandoned a wellbore which was lost due to cave-in and
immediately drilled a replacement well. Both the abandoned wellbore and the
replacement well are 12 kilometers southeast of the core Fairview area.
Subsequent to December 31, 1996, two wells were drilled, one offsetting the core
Fairview area and one six kilometers northwest of the core Fairview area. All
three of the wells drilled since September 30, 1996, exhibited high initial
water flow rates. Water flow rates are indicative of permeability of the coals,
which is necessary for commercial gas production.
During fiscal 1996, the Group began negotiations regarding a gas contract with a
Brisbane-based gas utility, which would call for the delivery of approximately
57 petajoules, or roughly 57 billion cubic feet, of gas over 15 years.
Negotiations are continuing, and the parties are reviewing a draft agreement
which would take effect upon completion of a connecting pipeline and gathering
facilities. The Group has applied for a pipeline license for the 17-mile line
which will connect the core Fairview area wells to the PGT Queensland Gas
pipeline. This pipeline was acquired during fiscal 1996 from the State of
Queensland by PGT Australia ("PGT"), a subsidiary of Pacific Gas Transmission, a
Portland, Oregon-based gas transmission company. PGT has informed the Group
that it intends to construct the 17-mile pipeline to connect the Fairview area
wells to the PGT Queensland Gas Pipeline, and that it plans to operate the line
as a part of its pipeline system. PGT has also informed the Company that
construction of the pipeline is expected to take approximately three months, and
that PGT expects to begin after clearance is received from the Queensland
Department
6
of Mines and Energy. The Group has been notified by PGT that they anticipate a
pipeline connection into the project area in the next few months. The Group has
also ordered compression and gathering equipment to be installed within the same
period. Connection to the PGT Queensland Gas Pipeline will provide access on
the PGT system to markets north of the ATP in Gladstone and Rockhampton, and the
possibility of "backhauls" south on other pipelines into the Brisbane market
area. Assuming completion of a new pipeline which PGT has announced it will
construct from the ATP area into the Brisbane area, the Group's gas could be
transported to both the Gladstone and Brisbane market areas on the PGT system.
Effective January 1, 1997, the Company increased its ownership in the Comet
Ridge project from 45.75% to 50.75% with the acquisition of an additional 5%
capital-bearing interest from an unaffiliated interest holder for approximately
$2,300,000. The purchase was financed through a loan from an affiliate of the
Company's largest shareholder. The Companys interest bears 50.75% of capital
costs and 47.58% of operating expenses and its net revenue interest is 42.35%
prior to project payout. Subsequent to project payout, the Company's interest
bears 40.60% of capital and operating expenses and its net revenue interest is
36.14%.
Although the Company cannot predict future capital requirements, in November
1996 it retained an international corporate finance firm to serve as the
Company's agent in seeking equity and debt financing sources in Australia, the
United States and Europe, with proceeds to be used to develop the Comet Ridge
project. There can be no assurance that sufficient capital will be obtained or,
if capital is obtained, that it will be on terms acceptable to the Company or on
a basis that meets the Company's objectives.
DOMESTIC EXPLORATION
MISSOURI RIVER PROJECT. The Company owns an 87.5% undivided interest in
approximately 45,000 acres in its Missouri River project area in the Williston
Basin of Montana. During fiscal 1995, a three-dimensional ("3-D") seismic
survey was conducted over approximately 30% of the project area, resulting in
the identification of several prospects. The Company drilled a dry hole on the
first prospect tested in February 1996. As of September 30, 1996, the Company's
investment in the project totaled approximately $2,420,000. An additional
$30,000 was incurred during the first quarter of fiscal 1997, bringing the total
investment to $2,450,000 as of December 31, 1996. During the quarter, the
Company continued its efforts to sell interests in the project to industry
partners for cash and/or a commitment to fund seismic or drilling expenditures.
On January 29, 1997, the Company entered into an agreement with another oil and
gas company covering 30,000 acres in the project. The other company agreed to
spend $150,000 in acquiring two-dimensional seismic data, and will then have an
option to acquire an undivided 50% interest in the acreage for an additional
$390,000 cash payment. The Company has also entered into a joint seismic
program with a different oil and gas company covering an additional 4,000 acres
in the Missouri River project area.
DIVIDE PROJECT. During fiscal 1996, the Company assembled a 30,000 acre
leasehold position in Divide County, North Dakota, and subsequently entered into
exploration agreements with two industry partners. The agreements included the
sale of a total of 75% of the Company's working interest for $975,000 in cash
and $256,000 in "carried" capital costs and provide for the three parties to
jointly pursue exploration activities over the acreage, including the
acquisition of 3-D seismic data and exploratory drilling. The parties have
identified numerous prospects in the Divide Project area, which is located in a
multi-pay area of the Williston Basin. Seismic data acquisition commenced in
November 1996 and initial drilling is expected to begin in the third quarter of
fiscal 1997. During the quarter ended December 31, 1996, the Company incurred
approximately $66,000 to acquire additional acreage in Divide County.
OTHER ACTIVITIES
The Alabama natural gas liquids ("NGL") fractionating plant, which the Company
and joint venture partners constructed in fiscal 1994 and 1995, began operations
in late November 1995 and has operated near full capacity for an extended
period. The results of the plant operations have been disappointing due to both
mechanical inefficiencies and changing market conditions for NGL products. A
new plant operator was appointed by the co-owners of the plant in November 1996
and certain mechanical modifications have been made. In January 1997, the
Company and a co-owner in the plant engaged a consulting engineering firm to
further investigate and analyze the operations of the plant and the marketing
and transportation of the plant products. The Company has an interest in plant
profits of 55% prior to payout and 47% thereafter. As of December 31, 1996, the
Company had invested $2,432,000, which is net of a distribution of $77,000 and
includes a net loss of $75,000 during fiscal 1996 and a net loss of $53,000
during the first quarter of fiscal 1997. The combined net loss of $128,000
represents the Company's share of the net loss from the Plant's operations from
7
from start-up through December 31, 1996. Before depreciation and amortization,
the Company's share of income for the quarter ended December 31, 1996, was
$32,000. The loss for the three months ended December 31, 1995, reflects the
results of start-up operations. The loss during the first quarter of fiscal
1997 is due to year-end maintenance to improve the plant's efficiency, and to a
decrease in inlet volumes of raw NGLs. The co-owners of the plant are currently
in the process of identifying additional sources of raw NGLs.
RESULTS OF OPERATIONS - COMPARISON OF THE THREE MONTHS ENDED DECEMBER 31, 1996,
AND 1995
The Company reported net income of $978,000 for the three months ended December
31, 1996 versus a net loss of $241,000 for the three months ended December 31,
1995. The gross profit from oil and gas sales increased $1,309,000, or 98%, to
$2,642,000 in the first quarter of fiscal 1997 from $1,333,000 in the prior year
quarter due primarily to higher oil and gas prices. The Company reported
operating income of $1,270,000 in the fiscal 1997 period versus an operating
loss of $44,000 in the corresponding period of fiscal 1996. Following are
detailed comparisons of the components of net income for the respective
periods:
Operating revenues for the three months ended December 31, 1996, increased
$1,481,000, or 56%, to $4,112,000 from $2,631,000 reported for the corresponding
fiscal 1996 period. Oil volumes produced during the fiscal 1997 quarter
increased 19% to 146,000 barrels from 123,000 barrels in the prior year's
quarter, increasing revenue by $365,000. Gas volumes produced increased 7% to
437,000 Mcf in the current quarter compared to 407,000 Mcf in the quarter ended
December 31, 1995, resulting in a $44,000 increase in revenues. These volume
increases are largely attributable to new production resulting from exploitation
and development drilling projects completed in the fourth quarter of fiscal
1996. Average oil prices increased 36% to $21.60 for the three months ended
December 31, 1996, from $15.88 for the corresponding prior year's quarter,
resulting in an $835,000 increase in revenue. Gas prices increased 39% to $2.05
in the current quarter versus $1.48 in the prior year's quarter, resulting in a
$249,000 revenue increase. Saltwater disposal and other revenues decreased
$12,000 from the corresponding fiscal 1996 period.
Operating expenses increased $172,000, or 13%, to $1,470,000 in the quarter
ended December 31, 1996, from $1,298,000 reported in the corresponding quarter
in fiscal 1996. The increase was primarily attributable to increased production
taxes resulting from higher revenues and to remedial work on mature properties.
The Company's average lifting cost per equivalent barrel produced increased to
$6.66 in the three months ended December 31, 1996, from $6.29 in the prior
year's three-month period.
General and administrative expenses increased $88,000, or 25%, to $437,000 in
the quarter ended December 31, 1996, from $349,000 in the quarter ended December
31, 1995. The increase was attributable to increased payroll costs and an
increase in legal and consulting fees during the fiscal 1997 quarter.
Depreciation, depletion and amortization ("DD&A") expense for the three months
ended December 31, 1996, decreased by $93,000, or 9%, to $935,000 from
$1,028,000 reported for the comparable fiscal 1996 period. The decrease is
primarily attributable to a lower DD&A rate per equivalent barrel resulting from
an increase in oil and gas reserve volumes as of September 30, 1996, compared to
September 30, 1995.
Interest income decreased $39,000, or 57%, to $29,000 in the quarter ended
December 31, 1996, from $68,000 in the corresponding prior year quarter. This
decrease is due to a decrease in the average balance of cash and cash
equivalents.
Dividend income decreased to -0- in the quarter ended December 31, 1996, from
$22,000 in the quarter ended December 31, 1995. Dividend income was accrued
during fiscal 1996 on 354,000 shares of convertible preferred stock in United
States Exploration, Inc. ("USXP"). The convertible preferred stock was
exchanged for common stock of USXP on September 30, 1996.
Interest expense decreased $11,000, or 4%, to $245,000 in the first quarter of
fiscal 1997 from $256,000 in the first quarter of fiscal 1996. When capitalized
interest is included, interest expense decreased by $14,000. The decrease is
attributable to reductions in long-term debt.
Income tax expense increased $20,000 to $23,000 in the first quarter of fiscal
1997 from $3,000 in the prior year quarter. The expense reflects an effective
rate of 2%, rather than 35%, because the Company has a net operating loss
carryover, but must pay federal alternative minimum tax at an effective rate of
2%. The expense in the prior year quarter reflects adjustments to prior year
income taxes.
8
The Company's equity in the loss of the NGL fractionating plant increased
$25,000, or 89%, to a loss of $53,000 in the three months ended December 31,
1996, from a loss of $28,000 in the prior year quarter. The loss in the first
quarter of fiscal 1997 is attributable to year-end maintenance and a decrease in
inlet volumes as discussed above. The loss in the fiscal 1996 quarter was a
result of start-up operations.
9
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
See Note 2 to the consolidated financial statements under Part I
- Item 1.
Item 2. Changes in Securities
None
Item 3. Defaults Upon Senior Securities
None
Item 4. Submission of Matters to a Vote of Security Holders
None
Item 5. Other Information
None
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits:
Filed in Part I
11. Computation of per share earnings
Filed in Part II
4.48 Promissory Note dated December 20, 1996, in the
amount of $2,300,000 between Registrant and Slough
Parks Incorporated, filed herewith.
4.49 Subordination Agreement dated December 20, 1996, by
and between Slough Parks Incorporated and Colorado
National Bank, filed herewith.
10.49 Purchase and Sale Agreement dated January 29, 1997,
between NationsBank of Texas, N.A., as Trustee for
Trusts #1190 and #1191 ("Seller") and Tipperary Oil
& Gas Corporation ("Buyer"), filed herewith.
10.50 Purchase and Sale Agreement dated January 29, 1997,
between NationsBank of Texas, N.A., as Trustee for
Trusts #1362, #1363 and #1364 ("Seller") and
Tipperary Oil & Gas Corporation ("Buyer"), filed
herewith.
10.51 Tipperary Corporation 1997 Long-Term Incentive Plan
filed as Exhibit A to the Registrant's Proxy
Statement for its Annual Meeting of Shareholders held
on January 28, 1997, and incorporated herein by
reference.
27 Financial Data Schedule.
(b) Reports on Form 8-K:
None
10
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Tipperary Corporation
---------------------
Registrant
Date: February 13, 1997 By: /s/ David L. Bradshaw
----------------------------------------
David L. Bradshaw, President, Chief
Executive Officer and Chairman of the
Board of Directors
Date: February 13, 1997 By: /s/ Paul C. Slevin
----------------------------------------
Paul C. Slevin, Chief Financial Officer
Date: February 13, 1997 By: /s/ Wayne W. Kahmeyer
----------------------------------------
Wayne W. Kahmeyer, Controller and
Principal Accounting Officer
11