FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 1996
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OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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________________________________________________________
Commission file number 1-10509
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SNYDER OIL CORPORATION
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(Exact name of registrant as specified in its charter)
Delaware 75-2306158
------------------------------- ---------------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
777 Main Street, Fort Worth, Texas 76102
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(Address of principal executive offices) (Zip Code)
(Registrant's telephone number, including area code) (817)338-4043
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(Former name, former address and former fiscal year, if changed since
last report.)
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 [ ].
31,560,257 Common Shares were outstanding as of May 6, 1996
PART I. FINANCIAL INFORMATION
The financial statements included herein have been prepared in
conformity with generally accepted accounting principles. The
statements are unaudited, but reflect all adjustments which, in the
opinion of management, are necessary to fairly present the Company's
financial position and the results of operations.
2
SNYDER OIL CORPORATION
CONSOLIDATED BALANCE SHEETS (Notes 1 and 2)
(In thousands)
December 31, March 31,
1995 1996
-------------- -------------
(Unaudited)
ASSETS
Current assets
Cash and equivalents $ 27,263 $ 43,335
Accounts receivable 29,259 32,870
Inventory and other 11,769 11,719
---------- ----------
68,291 87,924
---------- ---------
Investments (Note 4) 33,220 34,119
---------- ---------
Oil and gas properties, successful efforts method (Note 5) 675,961 687,745
Accumulated depletion, depreciation and amortization (240,744) (256,460)
--------- ---------
435,217 431,285
--------- ---------
Gas facilities and other (Note 5) 30,506 28,235
Accumulated depreciation (11,741) (9,873)
--------- ---------
18,765 18,362
--------- ---------
$ 555,493 $ 571,690
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable $ 36,353 $ 52,743
Accrued liabilities 26,096 25,964
--------- ---------
62,449 78,707
--------- ---------
Senior debt, net (Note 3) 150,001 156,001
Convertible subordinated notes (Note 3) 84,058 84,160
Other noncurrent liabilities (Notes 7 and 9) 20,016 13,947
Minority interest 3,601 3,951
Commitments and contingencies (Note 10)
Stockholders' equity (Note 6)
Preferred stock, $.01 par, 10,000,000 shares authorized,
6% Convertible preferred stock, 1,035,000 shares
issued and outstanding 10 10
Common stock, $.01 par, 75,000,000 shares authorized,
31,430,227 and 31,560,257 issued 314 316
Capital in excess of par value 265,911 264,645
Retained earnings (deficit) (29,001) (28,777)
Common stock held in treasury, 134,191 and 166,022 shares at cost (2,457) (2,715)
Foreign currency translation adjustment 380 1,212
Unrealized gain on investments (Note 4) 211 233
---------- ----------
235,368 234,924
---------- ----------
$ 555,493 $ 571,690
========== ==========
<FN>
The accompanying notes are an intergral part of these statements.
3
SNYDER OIL CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS (Notes 1 and 2)
(In thousands except per share data)
Three Months Ended March 31,
-----------------------------
1995 1996
------------ ------------
(Unaudited)
Revenues (Note 8)
Oil and gas sales $ 37,601 $ 36,122
Gas processing, transportation and marketing 13,566 4,451
Gains (loss) on sales of properties (Note 5) 732 (20)
Other 1,118 1,166
--------- ---------
53,017 41,719
--------- ---------
Expenses
Direct operating 12,980 10,759
Cost of gas and transportation 10,029 3,696
Exploration 1,121 514
General and administrative 4,558 3,868
Interest and other 6,404 4,293
Litigation settlement (Note 10) 4,400 -
Depletion, depreciation and amortization 19,986 16,771
--------- ---------
Income (loss) before taxes and minority interest (6,461) 1,818
--------- ---------
Provision (benefit) for income taxes (Note 7)
Current 25 25
Deferred (591) (335)
--------- ---------
(566) (310)
--------- ---------
Minority interest (86) (351)
--------- ---------
Net income (loss) $ (5,981) $ 1,777
========= =========
Net income (loss) per common share (Note 6) $ (.25) $ .01
========= =========
Weighted average shares outstanding (Note 6) 30,035 31,302
========= =========
<FN>
The accompanying notes are an integral part of these statements.
4
SNYDER OIL CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN
STOCKHOLDERS' EQUITY (Notes 1, 2 and 6)
(In thousands)
Preferred Stock Common Stock Capital in Retained
---------------------- -------------------- Excess of Earnings
Shares Amount Shares Amount Par Value (Deficit)
-------- -------- -------- -------- ----------- -----------
Balance, December 31, 1994 1,035 $ 10 30,209 $ 302 $ 255,961 $ 20,959
Common stock grants and
exercise of options - - 138 1 856 -
Issuance of common - - 1,083 11 13,021 -
Dividends - - - - (3,927) (10,129)
Net loss - - - - - (39,831)
-------- -------- -------- -------- ---------- ---------
Balance, December 31, 1995 1,035 10 31,430 314 265,911 (29,001)
Common stock grants and
exercise of options - - 130 2 770 -
Dividends - - - - (2,036) (1,553)
Net income - - - - - 1,777
-------- -------- -------- -------- ---------- ---------
Balance, March 31, 1996
(Unaudited) 1,035 $ 10 31,560 $ 316 $ 264,645 $ (28,777)
======== ======== ======== ======== ========== =========
<FN>
The accompanying notes are an integral part of these statements.
5
SNYDER OIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (Notes 1 and 2)
(In thousands)
Three Months Ended March 31,
----------------------------------
1995 1996
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(Unaudited)
Operating activities
Net income (loss) $ (5,981) $ 1,777
Adjustments to reconcile net income (loss) to net
cash provided by operations
(Gain) loss on sales of properties (732) 20
Exploration expense 1,121 514
Depletion, depreciation and amortization 19,986 16,771
Deferred taxes (591) (335)
Gain on sales of investments (1,236) (407)
Equity in losses of unconsolidated subsidiaries 562 88
Amortization of deferred credits (529) (534)
Changes in operating assets and liabilities
Decrease (increase) in
Accounts receivable (5,399) (3,611)
Inventory and other (1,234) 50
Increase (decrease) in
Accounts payable (2,209) 16,390
Accrued liabilities 4,825 1,050
Other liabilities (39) (5,415)
Other 49 25
---------- ----------
Net cash provided by operations 8,593 26,383
---------- ----------
Investing activities
Acquisition, development and exploration (44,601) (13,737)
Proceeds from investments 764 774
Outlays for investments - (165)
Proceeds from sales of properties 1,530 (63)
---------- ---------
Net cash used by investing (42,307) (13,191)
---------- ---------
Financing activities
Issuance of common (38) 487
Increase in indebtedness 31,008 6,102
Dividends (3,510) (3,589)
Deferred credits 1,748 (120)
---------- ----------
Net cash realized by financing 29,208 2,880
---------- ----------
Increase (decrease) in cash (4,506) 16,072
Cash and equivalents, beginning of period 21,733 27,263
---------- ----------
Cash and equivalents, end of period $ 17,227 $ 43,335
========== ==========
<FN>
The accompanying notes are an integral part of these statements.
6
SNYDER OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION AND NATURE OF BUSINESS
Snyder Oil Corporation (the "Company") is primarily engaged in
the acquisition, exploration, development and production of oil and
gas properties principally in the Rocky Mountain and Gulf Coast
regions of the United States. To a lesser extent, the Company
gathers, transports and markets natural gas generally in proximity
to its principal producing properties. The Company is also engaged
to a growing extent in international acquisition, exploration and
development. The Company, a Delaware corporation, is the successor
to a company formed in 1978.
Historically, the market for oil and gas has experienced
significant price fluctuations. Prices for gas in the Rocky
Mountain region, where the Company currently produces over 70% of
its natural gas, have traditionally been particularly volatile and
have been depressed since 1994. In large part, the decreased
prices are the result of increased production in the area and
limited transportation capacity to other regions of the country.
As a result, prices are particularly sensitive to local demand,
which has been depressed primarily due to unusually mild weather in
the region. Increases or decreases in prices received could have a
significant impact on the Company's future results of operations.
Subsequent to the end of the quarter, several significant
transactions were consummated or agreed upon. In mid-April, the
sale to two institutional investors of a 15.4% interest in the
Company's Russian subsidiary was consummated. The sale reduced
SOCO's net interest in the Permtex joint venture by approximately
3% and will result in a gain of approximately $2.5 million in the
second quarter. In late April, the Company agreed to acquire an
incremental interest in its Gulf of Mexico properties for a
purchase price of $15.5 million, effective January 1, 1996 and to
buy out all but one of the remaining shareholders in its
subsidiary, DelMar Petroleum, Inc. On May 2, the consolidation of
Gerrity Oil & Gas Corporation ("Gerrity") into the Company's
subsidiary, Patina Oil & Gas Corporation, was concluded (the
"Merger"). Simultaneously, a 45% interest in the Company's
Piceance Project was sold for $22 million and a joint venture to
further develop the properties was agreed upon. The sale fully
recovered the cost of the Company's Piceance acreage and will
result in a net gain of approximately $1.8 million in the second
quarter.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Risks and Uncertainties
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
Principles of Consolidation
The consolidated financial statements include the accounts of
Snyder Oil Corporation and its subsidiaries (collectively, the
Company). Affiliates in which the Company owns more than 50% are
fully consolidated, with the related minority interest being
deducted from subsidiary earnings and stockholders' equity.
Affiliates being accounted for in this manner include DelMar
Petroleum, Inc. Affiliates in which the Company owns 50% or less
are accounted for under the equity method. Affiliates being
accounted for in this manner include Command Petroleum Limited
("Command"), SOCO Perm Russia, Inc. ("SOCO Perm"), the Company's
Russian subsidiary, and SOCO Tamtsag Mongolia, Inc. ("Tamtsag").
The Company accounts for its interest in joint ventures and
partnerships using the proportionate consolidation method, whereby
its share of assets, liabilities, revenues and expenses are
consolidated with other operations.
7
Producing Activities
The Company utilizes the successful efforts method of
accounting for its oil and gas properties. Under successful
efforts, oil and gas leasehold costs are capitalized when incurred.
Unproved properties are assessed periodically within specific
geographic areas and impairments in value are charged to expense.
Exploratory expenses, including geological and geophysical expenses
and delay rentals, are charged to expense as incurred. Exploratory
drilling costs are initially capitalized, but charged to expense if
and when the well is determined to be unsuccessful. Costs of
productive wells, unsuccessful developmental wells and productive
leases are capitalized and amortized on a unit-of-production basis
over the life of the remaining proved or proved developed reserves,
as applicable. Gas is converted to equivalent barrels at the rate
of 6 Mcf to 1 barrel. Amortization of capitalized costs is
generally provided on a property-by-property basis. Estimated net
future dismantlement, restoration and abandonment costs (net of
estimated salvage values), if any, are accrued over the properties'
operating lives. Such costs are calculated at unit-of-production
rates based upon estimated proved recoverable reserves and are
taken into account in determining depletion, depreciation and
amortization.
Prior to the fourth quarter of 1995, the Company provided
impairments for significant proved and unproved oil and gas
property groups to the extent that net capitalized costs exceeded
the undiscounted future cash flows. During the three months ended
March 31, 1995, the Company did not provide for any impairments.
During the fourth quarter of 1995, the Company adopted Statement of
Financial Accounting Standards No. 121 ("SFAS 121"), "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets
to Be Disposed Of". SFAS 121 requires the Company to assess the
need for an impairment of capitalized costs of oil and gas
properties on a property-by-property basis. If an impairment is
indicated based on undiscounted expected future cash flows, then an
impairment is recognized to the extent that net capitalized costs
exceed discounted expected future cash flows. During the three
months ended March 31, 1996, the Company did not provide for any
impairments.
Foreign Currency Translation Adjustment
The Company's investment in its Australian affiliate is
accounted for using the equity method, whereby the cash basis
investment is increased for equity in earnings and decreased for
dividends, if any were received. The affiliate's functional
currency is the Australian dollar. The foreign currency
translation adjustments reported in the balance sheet are the
result of the translation of the Australian dollar balance sheet
into United States dollars at the balance sheet dates and changes
in the exchange rate subsequent to purchase.
Gas Imbalances
The Company uses the sales method to account for gas
imbalances. Under this method, revenue is recognized based on the
cash received rather than the Company's proportionate share of gas
produced. Gas imbalances at December 31, 1995 and March 31, 1996
were not significant.
Financial Instruments
The following table sets forth the book value and estimated
fair values of the Company's financial instruments:
December 31, March 31,
1995 1996
---------------------- ---------------------
(In thousands)
Book Fair Book Fair
Value Value Value Value
--------- --------- --------- ---------
Cash and equivalents $ 27,263 $ 27,263 $ 43,335 $ 43,335
Investments 33,220 52,203 34,119 74,037
Senior debt (150,001) (150,001) (156,001) (156,001)
Convertible subordinated notes (84,058) (79,997) (84,160) (72,881)
Commodities contracts - 11,623 - 16,993
Interest rate swap - 107 - (81)
8
The book value of cash and equivalents approximates fair value
because of the short maturity of those instruments. See Note (4)
for a discussion of the Company's investments. The fair value of
senior debt is presented at the current floating rate. The fair
value of the convertible subordinated notes was estimated based on
their closing prices on the New York Stock Exchange.
To a limited extent, the Company enters into commodities
contracts to hedge the price risk of a portion of its production.
Gains and losses on commodities contracts are deferred and
recognized in income as an adjustment to oil and gas sales revenue
when the related transaction being hedged is finalized (generally
on a monthly basis). In 1994, the Company entered into a gas swap
arrangement in order to lock in the price differential between the
Rocky Mountain and the NYMEX Henry Hub prices on a limited portion
of its gas production to reduce exposure to the Rocky Mountain spot
prices. The Company wanted to diversity its price risk between
Henry Hub and Rocky Mountain spot prices. At March 31, 1996, the
long-term contract in effect covered 20,000 MMBtu per day through
2004. In March 1996, that volume represented approximately 20% of
the Company's current Rocky Mountain gas production. The fair
value of the contract was based on the quoted market price of a
similar instrument of the same duration.
In September 1995, the Company entered into an interest rate
swap agreement for a principal amount of $50 million to reduce the
impact of changes in interest rates on its revolving credit
facility. The agreement requires that the Company pay the
counterparty interest at a fixed rate of 5.585%, and requires the
counterparty to pay the Company interest at the one month LIBOR
rate. Accounts receivable or payable under this agreement are
recorded as adjustments to interest expense and are generally
settled on a monthly basis. The agreement matures on September 26,
1997, with the counterparty having the option to extend it for
another two years. At March 31, 1996, the fair value of the
agreement was estimated as the net present value discounted at 10%
of cash flows based on the interest rate differential.
Other
All liquid investments with an original maturity of three
months or less are considered to be cash equivalents.
Certain amounts in prior years consolidated financial
statements have been reclassified to conform with current
classification.
In the opinion of management, those adjustments to the
financial statements (all of which are of a normal and recurring
nature) necessary to present fairly the financial position and
results of operations have been made. These interim financial
statements should be read in conjunction with the 1995 annual
report on Form 10-K.
(3) INDEBTEDNESS
The following indebtedness was outstanding on the respective
dates:
December 31, March 31,
1995 1996
------------- -------------
(In thousands)
Revolving credit facility $ 150,001 $ 156,001
Less current portion - -
----------- -----------
Senior debt, net $ 150,001 $ 156,001
=========== ===========
Convertible subordinated notes, net $ 84,058 $ 84,160
=========== ===========
The Company maintains a $500 million revolving credit
facility. The facility is divided into a $400 million long-term
portion and a $100 million short-term portion. The borrowing base
available under the facility was $225 million at March 31, 1996.
In May 1996, the borrowing base was reduced to $125 million upon
consummation of the Merger discussed in Note 5 below. Also in
9
conjunction with the Merger, Patina paid the Company $75 million
which was used to reduce the Company's borrowings under the
facility. The majority of the borrowings under the facility
currently bear interest at LIBOR plus .75% with the remainder at
prime, with an option to select CD plus .75%. The margin on LIBOR
or CD increases to 1% when the Company's consolidated senior debt
becomes greater than 80% of its consolidated tangible net worth as
defined. During the three months ended March 31, 1996, the average
interest rate under the revolver was 6.5%. The Company pays
certain fees based on the unused portion of the borrowing base.
Among other requirements, covenants require maintenance of $1.0
million in minimum working capital as defined, limit the incurrence
of debt and restrict dividends, stock repurchases, certain
investments, other indebtedness and unrelated business activities.
Such restricted payments are limited by a formula that includes
underwriting proceeds, cash flow and other items. Based on such
limitations, more than $100 million was available for the payment
of dividends and other restricted payments as of March 31, 1996.
In May 1994, the Company issued $86.3 million of 7%
convertible subordinated notes due May 15, 2001. The net proceeds
were $83.4 million. The notes are convertible into common stock at
$23.16 per share, and are redeemable at the option of the Company
on or after May 15, 1997, initially at 103.51% of principal, and at
prices declining to 100% at May 15, 2000, plus accrued interest.
Scheduled maturities of indebtedness for the next five years
are zero for the remainder of 1996, 1997, 1998 and 1999 and $156.0
million in 2000. The long-term portion of the revolving credit
facility is scheduled to expire in 2000; however, it is
management's policy to renew both the short-term and long-term
facility and extend the maturities on a regular basis.
Cash payments for interest were $4.0 million and $2.2 million,
respectively, for the three months ended March 31, 1995 and 1996.
(4) INVESTMENTS
The Company has investments in foreign and domestic energy
companies and long-term notes receivable. The following table sets
forth the book values and estimated fair values of the Company's
investments:
December 31, 1995 March 31, 1996
--------------------- -----------------------
(In thousands)
Book Fair Book Fair
Value Value Value Value
-------- -------- -------- -------
Equity method investments $ 30,901 $ 49,884 $ 32,260 $ 72,178
Marketable securities 652 652 233 233
Long-term notes receivable 1,667 1,667 1,626 1,626
-------- -------- -------- --------
$ 33,220 $ 52,203 $ 34,119 $ 74,037
======== ======== ======== ========
The Company follows SFAS 115, "Accounting for Certain
Investments in Debt and Equity Securities" which requires that
investments in marketable securities accounted for on the cost
method and long-term notes receivable must be adjusted to their
market value with a corresponding increase or decrease to
stockholders' equity. The pronouncement does not apply to
investments accounted for by the equity method.
The Company has an investment in Command, an Australian
exploration and production company, accounted for by the equity
method. Command is listed on the Australian Stock Exchange, and
holds interests in various international exploration and production
permits and licenses. In 1995, the Company acquired an additional
4.7 million shares of Command common stock in exchange for the
Company's interest in the Fejaj Permit area in Tunisia. The
Company will receive an additional 4.7 million shares if a
commercial discovery is made as the result of the initial 4,000
meter drilling commitment. As a result of this transaction, the
Company's ownership in Command was increased to 30.0% and a $1.4
million gain was recognized during 1995. The fair value of the
Company's investment in Command based on Command's closing price at
10
March 31, 1996 was $33.7 million, compared to a book value of $25.7
million.
In early 1993, the Company formed Permtex to develop proven
oil fields in the Volga-Urals Basin of Russia. To finance its
portion of planned development expenditures, the Company sold a
portion of its interest in the project to three industry
participants in 1994. As a result, its equity investment was
reduced from 50% to 20.6% and a $3.5 million net gain was recorded.
In 1995, the three industry participants paid the final
installments of their contributions to the venture and as a result,
the Company recognized an additional gain of $1.1 million. The
Russian investment had a book value of $4.6 million at March 31,
1996. In April 1996, the Company closed a private placement which
reduced its equity investment in Permtex to 17.5% and established a
fair value for the Company's remaining position of $22.7 million.
The Company expects to recognize a gain in the second quarter of
approximately $2.5 million as a result of this transaction.
In late 1994, the Company formed a consortium to explore the
Tamtsag Basin of eastern Mongolia. In late 1994 and early 1995,
the venture sold a portion of its equity to three industry
participants, one of which committed to fund the drilling of two
wells, the second purchased its interest for cash and a third
participant assigned its exploration rights in the basin to the
venture. Accordingly, the Company's equity investment was reduced
from 100% to 42% and had a book value at March 31, 1996 of $1.9
million. The fair value of the Company's investment, based on a
recent equity sale by one of the industry participants to another
entity, was approximately $15.8 million at March 31, 1996. The
first well was drilled in the second quarter 1995 and found to be
noncommercial. The second well was spudded in the third quarter
and encountered hydrocarbons, but testing was suspended until April
1996 when the proper equipment could be mobilized. Well testing
recently began.
The Company had investments in equity securities of publicly
traded domestic energy companies accounted for on the cost method,
with a total cost at December 31, 1995 and March 31, 1996 of
$328,000 and zero. The market value of these securities at
December 31, 1995 and March 31, 1996 approximated $652,000 and
$233,000. During the three months ended March 31, 1996, the
Company sold substantially all of its remaining investments in
these securities for $733,000 and recognized a corresponding gain
of $407,000. The remainder of these securities were sold in April
1996 for a gain of approximately $233,000. In accordance with SFAS
115 at December 31, 1995 and March 31, 1996, investments were
increased by $324,000 and $233,000 of gross unrealized holding
gains, stockholders' equity was increased by $211,000 and $233,000
and deferred taxes payable were increased by $113,000 and zero.
The Company holds long-term notes receivable due from
privately held corporations with a book value of $1.7 million and
$1.6 million at December 31, 1995 and March 31, 1996. All notes
are secured by certain assets, including stock and oil and gas
properties. The Company believes that, based on existing market
conditions, the balances will be recovered in one to five years.
At December 31, 1995 and March 31, 1996, the fair value of the
notes receivable, based on existing market conditions and the
anticipated future net cash flow related to the notes, approximated
their carrying cost.
11
(5) OIL AND GAS PROPERTIES AND GAS FACILITIES
The cost of oil and gas properties at December 31, 1995 and
March 31, 1996 includes $24.2 million and $24.7 million,
respectively, of unevaluated leasehold. Such properties are held
for exploration, development or resale and are excluded from
amortization. The following table sets forth costs incurred
related to oil and gas properties and gas processing and
transportation facilities:
Three
Year Ended Months Ended
December 31, March 31,
1995 1996
------------- --------------
(In thousands)
Proved acquisitions $ 13,675 $ 1,554
Acreage acquisitions 7,388 438
Development 62,578 9,669
Gas processing, transportation and other 7,886 653
Exploration 8,214 593
----------- ----------
$ 99,741 $ 12,907
=========== ==========
Of the total development expenditures, $3.3 million was
concentrated in the Piceance Basin of western Colorado where six
wells were placed on sales with two in progress at quarter end. In
the Green River Basin of southern Wyoming, $2.2 million was
incurred to place five wells on sales with three in progress at
quarter end. The Company expended $2.0 million offshore in the
Gulf of Mexico, with two wells placed on sales and two wells in
progress at quarter end. In the horizontal drilling program in the
Giddings Field of southeast Texas, $1.5 million was incurred to
place three wells on sales with three in progress at quarter end.
In January 1996, the Company entered into an agreement whereby
the Wattenberg operations of the Company will be consolidated with
Gerrity. As a result, the Company will own 70% of the common stock
and the former Gerrity shareholders will own 30% of the common
stock of a new public company which will be known as Patina Oil &
Gas Corporation ("Patina"). On May 2, 1996, the Merger occurred.
The Merger will be accounted for by Patina as a purchase of
Gerrity. As the Company will own more than 50% of Patina, Patina
will be consolidated into the Company's financial statements.
Subsequent to quarter end, the Company sold a 45% interest in
its Piceance Basin holdings (the "Piceance Transaction") for a
gross purchase price of approximately $22 million. The Company
expects to recognize a net gain of approximately $1.8 million in
the second quarter as a result of this transaction.
In April 1996, the Company signed a letter of intent to
acquire an incremental interest in certain properties located in
the Gulf of Mexico for a gross purchase price of approximately
$15.5 million. The acquisition is expected to close in the second
quarter.
12
The following table summarizes the unaudited pro forma effects
on the Company's financial statements assuming significant
acquisitions and divestitures consummated during 1995 and 1996
(including the Merger and the Piceance Transaction which were yet
to be completed as of March 31, 1996) had been consummated on March
31, 1996 (for balance sheet data) and January 1, 1995 and 1996 (for
statement of operations data). The pro forma effect of the Merger
is based on assumptions set at the time of the filing of Patina's
registration statement declared effective by the Securities and
Exchange Commission. Future results may differ substantially from
pro forma results due to changes in oil and gas prices, production
declines and other factors. Therefore, pro forma statements cannot
be considered indicative of future operations.
As of or for As of or for
the Year Ended the Three Months
December 31, Ended March 31,
1995 1996
-------------- ----------------
(In thousands, except per share data)
Total assets $ 555,493 $ 779,663
Oil and gas sales $ 193,930 $ 47,747
Total revenues $ 221,636 $ 53,528
Production direct operating margin $ 134,628 $ 34,886
Net income (loss) $ (34,317) $ 3,095
Net income (loss) per common share $ (1.30) $ 0.05
Weighted average shares outstanding 31,269 31,302
In addition to the above pro forma effects, because Patina
will be consolidated into the Company's financial statements but
will not be consolidated into the Company's federal income tax
return, the Company believes it will be required to recognize a one
time non-cash charge in the second quarter of approximately $25
million to $28 million of deferred tax expense related to the
Merger.
(6) STOCKHOLDERS' EQUITY
A total of 75 million common shares, $.01 par value, are
authorized of which 31.4 million were issued at March 31, 1996. In
1994, the Company granted 2 million warrants in exchange for the
right to drill wells on certain acreage in the Wattenberg area.
The exercise price of the warrants is $21.60 per share with one
million expiring in February 1998 and the remaining one million in
February 1999. For financial reporting purposes, the warrants were
valued at $3.5 million, which was recorded as an increase to oil
and gas properties and capital in excess of par value. In 1995,
the Company issued 1.2 million shares of common stock, with 1.1
million shares issued in exchange for acquired property interests
and 138,000 shares issued primarily for the exercise of stock
options by employees (for which 12,000 shares were received as
consideration in lieu of cash and are held in treasury). During
the three months ended March 31, 1996, the Company issued 130,000
shares primarily for the exercise of stock options by employees
(for which 32,000 shares were received as consideration in lieu of
cash and are held in treasury). Quarterly dividends of $.065 per
share were paid in 1995 and the first quarter of 1996. For book
purposes, subsequent to June 1995, the common stock dividends were
in excess of retained earnings and as such have been and will
continue to be treated as distributions of capital.
A total of 10 million preferred shares, $.01 par value, are
authorized. In 1993, 4.1 million depositary shares (each
representing a one quarter interest in one share of $100
liquidation value stock) of 6% preferred stock were sold through an
underwriting. The net proceeds were $99.3 million. The stock is
convertible into common stock at $21.00 per share and is
exchangeable at the option of the Company for 6% convertible
subordinated debentures on any dividend payment date. The 6%
convertible preferred stock is currently redeemable at the option
of the Company. The liquidation preference is $25.00 per
depositary share, plus accrued and unpaid dividends. The Company
paid $6.2 million and $1.6 million ($1.50 per 6% convertible
depositary share per annum), respectively, in preferred dividends
during 1995 and the three months ended March 31, 1996.
13
The Company maintains a stock option plan for employees
providing for the issuance of options at prices not less than fair
market value. Options to acquire up to three million shares of
common stock may be outstanding at any given time. The specific
terms of grant and exercise are determinable by a committee of
independent members of the Board of Directors. The majority of
currently outstanding options vest over a three-year period (30%,
60%, 100%) and expire five years from date of grant.
In 1990, the shareholders adopted a stock grant and option
plan (the "Directors' Plan") for non-employee Directors of the
Company. The Directors' Plan provides for each non-employee
director to receive 500 common shares quarterly in payment of their
annual retainer. It also provides for 2,500 options to be granted
annually to each non-employee Director. The options vest over a
three-year period (30%, 60%, 100%) and expire five years from date
of grant.
Earnings per share are computed by dividing net income, less
dividends on preferred stock, by average common shares outstanding.
Net income (loss) available to common for the three months ended
March 31, 1995 and 1996, was ($7.5) million and $224,000,
respectively. Differences between primary and fully diluted
earnings per share were insignificant for all periods presented.
(7) FEDERAL INCOME TAXES
At March 31, 1996, the Company had no liability for foreign
taxes. A reconciliation of the United States federal statutory
rate to the Company's effective income tax rate as they apply to
the benefit for the three months ended March 31, 1995 and 1996
follows:
Three Months Ended March 31,
----------------------------
1995 1996
----------- -----------
Federal statutory rate (35%) 35%
Utilization of net deferred tax asset (56%)
Loss in excess of net deferred tax liability 26% -
------- -------
Effective income tax rate (9%) (21%)
======= =======
For tax purposes, the Company had regular net operating loss
carryforwards of $151.5 million and alternative minimum tax loss
carryforwards of $9.6 million at December 31, 1995. These
carryforwards expire between 1997 and 2010. At December 31, 1995,
the Company had alternative minimum tax credit carryforwards of
$1.3 million which are available indefinitely. Current income
taxes shown in the financial statements reflect estimates of
alternative minimum taxes.
(8) MAJOR CUSTOMERS
For the three months ended March 31, 1995 and 1996, no
purchaser accounted for more than 10% of revenues. Management
believes that the loss of any individual purchaser would not have a
material adverse impact on the financial position or results of
operations of the Company.
(9) DEFERRED CREDITS
In 1992, the Company formed a partnership to monetize Section
29 tax credits to be realized from the Company's properties, mainly
in the DJ Basin. Contributions of $12.8 million were received
through 1995 which is expected to increase net income through mid
1996. A revenue increase of more than $.40 per Mcf is realized on
production generated from qualified Section 29 properties in this
arrangement. The Company recognized $529,000 and $534,000 of this
revenue during the three months ended March 31, 1995 and 1996. The
Company has reached an agreement to replace the existing
partnership to monetize Section 29 tax credits. The new agreement,
involving both properties being contributed to Patina in
conjunction with the Merger as well as properties retained by the
Company, provides for the Company to receive proceeds from the sale
of an interest in such oil and gas properties which will entitle
the purchaser to receive Section 29 tax credits associated with
future natural gas production from the properties. The Company
will retain a variable production payment from the properties. As
a result, this transaction is anticipated to increase cash flow and
14
net income through 2002. A revenue increase of more than $.40 per
Mcf is expected to be realized on production generated from
qualified Section 29 properties in this arrangement.
(10) COMMITMENTS AND CONTINGENCIES
The Company rents office space and gas compressors at various
locations under non-cancelable operating leases. Minimum future
payments under such leases approximate $1.5 million for the
remainder of 1996, $2.1 million for 1997, $2.2 million for 1998 and
$2.4 million for 1999 and 2000.
In April 1995, the Company settled a lawsuit in Harris County,
Texas filed by certain landowners relating to certain alleged
problems at a Company well site. The Company recorded a charge of
$4.4 million during the first quarter to reflect the cost of the
settlement. A primary insurer honored its commitments in full and
participated in the settlement. The Company's excess carriers have
declined, to date, to honor indemnification for the loss. Based on
the advice of counsel, the Company is pursuing the non-
participating carriers for the great majority of the cost of
settlement. However, given the time period which may be involved
in resolving the matter, the full amount of the settlement was
provided for in the financial statements in the first quarter of
1995.
In August 1995, the Company was sued in the United States
District Court of Colorado by seven plaintiffs purporting to
represent all persons who, at any time since January 1, 1960, have
had agreements providing for royalties from gas production in
Colorado to be paid by the Company under a number of various lease
provisions. The plaintiffs allege that the Company improperly
deducted unspecified "post-production" costs incurred by the
Company prior to calculating royalty payments in breach of the
relevant lease provisions and that the Company fraudulently
concealed that fact from plaintiffs. The plaintiffs have recently
amended the complaint to allege that the Company has also underpaid
royalties on oil production. The plaintiffs seek unspecified
compensatory and punitive damages and a declaratory judgment that
the Company is not permitted to deduct post-production costs prior
to calculating royalties paid to the class. The Company believes
that its calculations of royalties are and have been proper under
the relevant lease provisions, and intends to defend this and any
similar suits vigorously. At this time, the Company is unable to
estimate the range of potential loss, if any, from this
uncertainty. However, the Company believes the resolution of this
uncertainty should not have a material adverse effect upon the
Company's financial position, although an unfavorable outcome in
any reporting period could have a material impact on the Company's
results of operations for that period.
In 1993, the Company was granted a $2.7 million judgment in
litigation involving the allocation of proceeds from a pipeline
dispute. On appeal, the appellate court upheld the verdict but
reduced the judgment to approximately $1.4 million plus interest.
The judgment had been appealed to the Oklahoma supreme court but
the appeal was recently denied. Net judgment proceeds of
approximately $1.5 million, including interest, were received in
April 1996 and will be reflected in the second quarter.
The financial statements reflect favorable legal proceedings
only upon receipt of cash, final judicial determination or
execution of a settlement agreement. The Company is a party to
various other lawsuits incidental to its business, none of which
are anticipated to have a material adverse impact on its financial
position or results of operations.
15
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Results of Operations
Total revenues for the three months ended March 31, 1996
declined 21% to $41.7 million. The revenue decrease included a
$9.1 million decline in gas processing, transportation and
marketing revenues primarily as a result of the sale of the
Wattenberg gas facilities in 1995. Oil and gas sales declined 4%
to $36.1 million. The decrease was due to a 20% decline in
equivalent oil and gas production almost offset by a 20% increase
in the average price received per equivalent barrel for the same
period in 1995. However, production as compared to the fourth
quarter of 1995 remained relatively constant. Net income for the
first quarter of 1996 was $1.8 million as compared to a net loss of
$6.0 million for the same period in 1995. The increase in net
income is primarily attributable to a $4.4 million non-recurring
charge related to a litigation settlement in the first quarter
1995, $3.3 million less of depletion, depreciation and amortization
in 1996 and $2.1 million less of interest and other expense. These
items were offset somewhat by the effect of the Wattenberg gas
facilities sales. Net income per common share rose to $.01
compared to net loss of $.25 in 1995.
Revenues from production operations less direct operating
expenses were $25.4 million, slightly above the prior year quarter.
Average daily production in the first quarter of 1996 was 9,039
barrels and 132 MMcf (31,007 barrels of oil equivalent), decreases
of 30% and 17%, respectively. However, as compared to the fourth
quarter of 1995, production remained relatively stable (30,878
barrels of oil equivalent). The production decreases resulted
primarily from the Company's reduced development schedule in 1996,
due to poor gas prices, together with the effects of property sales
in 1995. Average oil prices increased to $17.95 per barrel
compared to $16.40 received in the first quarter of 1995. Natural
gas prices averaged $1.78 per Mcf, a 36% increase from the $1.31
received in first quarter 1995. The increase was primarily
attributable to prices finally rebounding in areas outside of the
Rocky Mountain region. Unfortunately, prices within the Rocky
Mountain region continue to be severely depressed. First quarter
operating expenses per equivalent barrel (including production
taxes) remained relatively stable at $3.81 per equivalent barrel as
compared to $3.68 in the comparable 1995 period.
The direct operating margin from gas processing,
transportation and marketing activities for the quarter decreased
by 79% to $755,000 from $3.5 million in 1995. The decrease
resulted primarily from a reduction in processing margins due to
the sale of the Company's Wattenberg gas facilities. The Company
realized almost $80 million in sales proceeds during 1995 on the
facilities and recognized a total of $8.7 million in gains during
the 1995 year. The direct operating margin was also impacted by a
loss of $150,000 related to an Oklahoma cogeneration facility gas
supply contract. The loss compares to income in the first quarter
of 1995 of $355,000. A contractual limitation of the contract
sales price and rising gas purchase cost resulted in the loss.
Loss on sales of properties was $20,000 for the quarter as
compared to a gain of $732,000 in the prior year quarter. Both the
gain and the loss resulted from small property sales related to the
ongoing program to dispose of non-strategic assets. Other income
was $1.2 million in the first quarter of 1996 compared to $1.1
million in 1995. The 1996 other income consisted primarily of a
gain on sale of marketable securities, lease bonuses and delay
rentals received on Company owned minerals and interest income
whereas the 1995 amount also included gains on sales of partial
interests in the Company's international ventures partially offset
by equity in losses of international subsidiaries.
Exploration expenses in 1996 decreased to $514,000 from $1.1
million in the first quarter 1995. The decrease resulted primarily
from discontinuation of certain exploration projects located in New
Mexico and Wyoming.
General and administrative expenses, net of reimbursements,
for first quarter 1996 were $3.9 million, a 15% decrease from the
same period in 1995. The decrease is attributable to previously
disclosed reductions in personnel in addition to a $600,000 charge
for severance costs related to the reduction in personnel that was
recorded in the first quarter of 1995. The decrease was partially
offset by decreased reimbursements due primarily to the reduced
drilling activities.
16
Interest and other expense was $4.3 million compared to $6.4
million in the first quarter 1995. The majority of the decrease is
the result of the significant decrease in average outstanding debt
levels due to sales of non-strategic assets and lower average
interest rates. The litigation settlement of $4.4 million was a
non-recurring charge recorded in the first quarter of 1995 as the
result of a lawsuit in Harris County, Texas filed by certain
landowners relating to certain alleged problems at a Company well
site that was settled in April 1995 at year end 1995.
Depletion, depreciation and amortization expense for the first
quarter decreased 16% from the same period in 1995. This decrease
is due to the decline in production as compared to 1995. The
decrease due to declining production was offset somewhat by a
higher depletion, depreciation and amortization rate of $5.56 per
equivalent barrel compared to $4.84 in 1995. The primary cause for
the increased rate was a downward revision in reserve quantities
due to proved undeveloped reserves being classified as uneconomic
at then current price levels at year end 1995.
Development, Acquisition and Exploration
During the three months ended March 31, 1996, the Company
incurred $12.9 million in capital expenditures, including $9.7
million for oil and gas development, $2.0 million for acquisitions,
$593,000 for exploration, $420,000 for gas facility expansion and
$233,000 for field and office equipment.
Of the total development expenditures, $3.3 million was
concentrated in the Piceance Basin of western Colorado where six
wells were placed on sales with two in progress at quarter end. In
the Green River Basin of southern Wyoming, $2.2 million was
incurred to place five wells on sales with three in progress at
quarter end. The Company expended $2.0 million offshore in the
Gulf of Mexico, with two wells placed on sales and two wells in
progress at quarter end. In the horizontal drilling program in the
Giddings Field of southeast Texas, $1.5 million was incurred to
place three wells on sales with three in progress at quarter end.
During the three months ended March 31, 1996, the Company
expended $2.0 million relating to acquisitions. Of this amount,
$815,000 was for producing properties, $739,000 was for capitalized
costs associated with the Merger and $438,000 was for acreage
purchases in or around the Company's operating hubs.
In January 1996, the Company entered into an agreement whereby
the Wattenberg operations of the Company will be consolidated (the
"Merger") with Gerrity Oil & Gas Corporation ("Gerrity"). As a
result, the Company will own 70% of the common stock and the former
Gerrity shareholders will own 30% of the common stock of a new
public company which will be known as Patina Oil & Gas Corporation
("Patina"). On May 2, 1996, the Merger occurred. The Merger will
be accounted for by Patina as a purchase of Gerrity. As the
Company will own more than 50% of Patina, Patina will be
consolidated into the Company's financial statements.
In April 1996, the Company agreed to acquire an incremental
interest in its Gulf of Mexico properties for a purchase price of
$15.5 million, effective January 1, 1996 and to buy out all but one
of the remaining shareholders in its subsidiary, DelMar Petroleum,
Inc.
Financial Condition and Capital Resources
At March 31, 1996, the Company had total assets of $571.7
million. Total capitalization was $475.1 million, of which 49% was
represented by stockholder's equity, 33% by senior debt, and 18% by
subordinated debt. During the three months ended March 31, 1996,
net cash provided by operations was $26.4 million, an increase of
207% compared to 1995. As of March 31, 1996, commitments for
capital expenditures totalled $3.5 million. The Company
anticipates that 1996 expenditures for development drilling will
approximate $55 million. The level of these and other future
expenditures is largely discretionary, and the amount of funds
devoted to any particular activity may increase or decrease
significantly, depending on available opportunities and market
conditions. The Company plans to finance its ongoing development,
acquisition and exploration expenditures using internally generated
17
cash flow, asset sales proceeds and existing credit facilities. In
addition, joint ventures or future public and private offerings of
debt or equity securities may be utilized. As a result of the
Merger, the Company expects the transaction to result in increased
consolidated net cash provided by operations, although cash
generated by Patina will be retained by Patina and will not be
available to fund the Company's other operations or to pay
dividends to its stockholders.
The Company maintains a $500 million revolving credit
facility. The facility is divided into a $100 million short-term
portion and a $400 million long-term portion that expires on
December 31, 2000. Management's policy is to renew the facility on
a regular basis. Credit availability is adjusted semiannually to
reflect changes in reserves and asset values. The borrowing base
available under the facility at March 31, 1996 was $225 million.
In May 1996, the borrowing base was reduced to $125 million upon
consummation of the Merger. Also in conjunction with the Merger,
Patina paid the Company $75 million which was used to reduce the
Company's borrowings under the facility. The majority of the
borrowings under the facility currently bear interest at LIBOR plus
.75% with the remainder at prime. The Company also has the option
to select CD plus .75%. The margin on LIBOR or CD loans increases
to 1% when the Company's consolidated senior debt becomes greater
than 80% of its consolidated tangible net worth as defined.
Financial covenants limit debt, require maintenance of $1.0 million
in minimum working capital as defined and restrict certain
payments, including stock repurchases, dividends and contributions
or advances to unrestricted subsidiaries. Such restricted payments
are limited by a formula that includes underwriting proceeds, cash
flow and other items. Based on such limitations, more than $100
million was available for the payment of dividends and other
restricted payments as of December 31, 1995.
In 1994, the Company executed an agreement with Union Pacific
Resources Corporation ("UPRC") whereby the Company gained the right
to drill wells on UPRC's previously uncommitted acreage in the
Wattenberg area. UPRC retained a royalty and the right to
participate as a 50% working interest owner in each well, and
received warrants to purchase two million shares of Company stock.
In February 1995, the exercise prices were reset to $21.60 per
share and their expiration extended one year. One million of the
warrants expire in February 1998 and the other million expire in
February 1999. In early 1995, the Company paid UPRC $400,000 for
an extension of the time period to drill the commitment wells and
released a portion of the outlying acreage committed to the
venture. During 1995, the Company drilled less than the required
minimum number of wells in the UPRC agreement. UPRC has asserted
that the Company's right to earn additional acreage under the
agreement terminated on December 31, 1995 and that the Company is
required to pay approximately $4.1 million in penalties to UPRC.
Arbitration proceedings on the matter have been initiated. The
Company established a reserve for these penalties in 1995.
In 1992, the Company formed a partnership to monetize Section
29 tax credits to be realized from the Company's properties, mainly
in the DJ Basin. Contributions of $12.8 million were received
through 1995 which is expected to increase net income through mid
1996. A revenue increase of more than $.40 per Mcf is realized on
production generated from qualified Section 29 properties in this
arrangement. The Company recognized $529,000 and $534,000 of this
revenue during the three months ended March 31, 1995 and 1996. The
Company has reached an agreement to replace the existing
partnership to monetize Section 29 tax credits. The new agreement,
involving both properties being contributed to Patina in
conjunction with the Merger as well as properties retained by the
Company, provides for the Company to receive proceeds from the sale
of an interest in such oil and gas properties which will entitle
the purchaser to receive Section 29 tax credits associated with
future natural gas production from the properties. The Company
will retain a variable production payment from the properties. As
a result, this transaction is anticipated to increase cash flow and
net income through 2002. A revenue increase of more than $.40 per
Mcf is expected to be realized on production generated from
qualified Section 29 properties in this arrangement.
The Company maintains a program to divest marginal properties
and assets which do not fit its long range plans. During the three
months ended March 31, 1995, the Company received $1.5 million in
proceeds from the sale of oil and gas properties. The proceeds
were applied to reduce the Company's outstanding senior debt.
There were no significant sales during the first quarter of 1996.
However, subsequent to quarter end, the Company sold a 45% interest
in its Piceance Basin holdings for a gross purchase price of
approximately $22 million. The Company expects to recognize a net
gain of approximately $1.8 million in the second quarter as a
result of this transaction.
The Company believes that its capital resources are adequate
to meet the requirements of its business. However, future cash
flows are subject to a number of variables including the level of
production and oil and gas prices, and there can be no
18
assurance that operations and other capital resources will provide
cash in sufficient amounts to maintain planned levels of capital
expenditures or that increased capital expenditures will not be
undertaken.
Inflation and Changes in Prices
While certain of its costs are affected by the general level
of inflation, factors unique to the petroleum industry result in
independent price fluctuations. Over the past five years,
significant fluctuations have occurred in oil and gas prices.
Although it is particularly difficult to estimate future prices of
oil and gas, price fluctuations have had, and will continue to
have, a material effect on the Company.
The following table indicates the average oil and gas prices
received over the last five years and highlights the price
fluctuations by quarter for 1995 and 1996. Average gas prices
prior to 1994 exclude Mississippi gas production sold under a high
price contract. In 1993, the Company renegotiated the gas contract
and received a substantial payment. Average gas prices for 1995
and for the first quarter of 1996 were increased by $.06 and $.16
per Mcf, respectively, by the benefit of the Company's hedging
activities. Average price computations exclude contract
settlements and other nonrecurring items to provide comparability.
Average prices per equivalent barrel indicate the composite impact
of changes in oil and gas prices. Natural gas production is
converted to oil equivalents at the rate of 6 Mcf per barrel.
Average Prices
-------------------------------------
Crude Oil Per
and Natural Equivalent
Liquids Gas Barrel
--------- --------- ----------
(Per Bbl) (Per Mcf)
Annual
------
1991 $ 20.62 $ 1.68 $ 14.36
1992 18.87 1.74 13.76
1993 15.41 1.94 13.41
1994 14.80 1.67 11.82
1995 16.96 1.35 11.00
Quarterly
---------
1995
----
First $ 16.40 $ 1.31 $ 10.66
Second 17.52 1.29 10.95
Third 17.05 1.30 10.81
Fourth 16.84 1.55 11.69
1996
----
First $ 17.95 $ 1.78 $ 12.80
In March 1996, the Company received an average of $19.37 per
barrel and $1.73 per Mcf for its production.
19
PART II. OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits -
10.11.4 Fourth Amendment dated as of April 4, 1996 to
Fifth Restated Credit Agreement
12 Computation of Ratio of Earnings to Fixed Charges
and Ratio of Earnings to Combined Fixed Charges
and Preferred Stock Dividends.
27 Financial Data Schedule
(b) The following report on Form 8-K was filed during the
quarter ended March 31, 1996:
1. January 29, 1996: Item 5. Other Events.
20
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.
SNYDER OIL CORPORATION
By (James H. Shonsey)
--------------------------------
James H. Shonsey, Vice President
May 6, 1996