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 SEPTEMBER 30, 1996
-------------------------
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(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
- -----------------------------------------------------------------------------
DELAWARE 75-2306158
- ------------------------------- -------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
777 MAIN STREET, FORT WORTH, TEXAS 76102
- --------------------------------------- ------------------
(Address of principal executive offices) (Zip Code)
(Registrant's telephone number, including area code) (817) 338-4043
----------------
- -------------------------------------------------------------------------------
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 .
31,124,157 Common Shares were outstanding as of November 7, 1996
<PAGE>
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 results of
operations.
2
<PAGE>
<TABLE>
SNYDER OIL CORPORATION
CONSOLIDATED BALANCE SHEETS (NOTES 1 AND 2)
(IN THOUSANDS)
<CAPTION>
DECEMBER 31, SEPTEMBER 30,
1995 1996
------------- --------------
(UNAUDITED)
ASSETS
<S> <C> <C>
Current assets
Cash and equivalents ...................................................... $ 27,263 $ 39,957
Accounts receivable ....................................................... 29,259 49,504
Inventory and other ....................................................... 11,769 9,980
----------- -----------
68,291 99,441
----------- -----------
Investments (Note 4) ........................................................... 33,220 43,267
----------- -----------
Oil and gas properties, successful efforts method (Note 5) ..................... 675,961 903,795
Accumulated depletion, depreciation and amortization ...................... (240,744) (297,176)
----------- -----------
435,217 606,619
----------- -----------
Gas facilities and other (Note 5) .............................................. 30,506 34,529
Accumulated depreciation and amortization ................................. (11,741) (15,547)
----------- -----------
18,765 18,982
----------- -----------
$ 555,493 $ 768,309
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable .......................................................... $ 36,353 $ 61,148
Accrued liabilities ....................................................... 26,096 35,104
---------- -----------
62,449 96,252
---------- -----------
Senior debt, net (Note 3) ...................................................... 150,001 159,251
Subordinated notes (Note 3) .................................................... - 103,264
Convertible subordinated notes (Note 3) ........................................ 84,058 80,656
Other noncurrent liabilities (Note 7) ......................................... 20,016 20,659
Minority interest .............................................................. 3,601 87,235
Commitments and contingencies (Note 9)
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 31,367,537 issued ...................................... 314 314
Capital in excess of par value ............................................ 265,911 258,273
Retained earnings (deficit) ............................................... (29,001) (36,305)
Common stock held in treasury, 134,191 and 250,000 shares at cost ......... (2,457) (3,510)
Foreign currency translation adjustment ................................... 380 2,210
Unrealized investments gains (Note 4) ..................................... 211 -
----------- -----------
235,368 220,992
----------- -----------
$ 555,493 $ 768,309
=========== ===========
The accompanying notes are an integral part of these statements.
</TABLE>
3
<PAGE>
<TABLE>
SNYDER OIL CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS (NOTES 1 AND 2)
(IN THOUSANDS EXCEPT PER SHARE DATA)
<CAPTION>
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30, ENDED SEPTEMBER 30,
-------------------------- ------------------------
1995 1996 1995 1996
---------- ---------- ---------- ----------
(UNAUDITED)
<S> <C> <C> <C> <C>
Revenues (Note 8)
Oil and gas sales ............................... $ 34,998 $ 46,347 $ 111,405 $ 126,799
Gas processing, transportation and marketing .... 9,349 4,702 34,327 13,497
Gains on sales of properties (Note 5) ........... 9,706 7,987 11,536 11,109
Other ........................................... (3,214) 3,439 3,730 9,557
---------- ---------- --------- ---------
..................................................... 50,839 62,475 160,998 160,962
---------- ---------- --------- ---------
Expenses
Direct operating ................................ 13,660 13,084 41,162 36,463
Cost of gas and transportation .................. 7,663 3,976 26,136 11,087
Exploration ..................................... 5,304 1,996 7,362 2,800
General and administrative ...................... 5,057 4,732 13,941 11,309
Interest and other .............................. 7,161 7,719 21,145 20,898
Litigation settlement (Note 9) .................. - - 4,400 -
Loss on sale of subsidiary interest (Note 5) .... - - - 15,481
Depletion, depreciation and amortization ........ 22,540 24,673 63,201 64,189
---------- ---------- ---------- ----------
Income (loss) before taxes and minority interest ..... (10,546) 6,295 (16,349) (1,265)
---------- ---------- ---------- ----------
Provision (benefit) for income taxes (Note 7)
Current ......................................... - - 25 33
Deferred ........................................ (1,120) 652 (1,711) 317
---------- ---------- -------- ----------
(1,120) 652 (1,686) 350
---------- ---------- -------- ----------
Minority interest .................................... (180) (83) (399) (1,031)
---------- ---------- -------- ---------
Net income (loss) .................................... $ (9,606) $ 5,560 $ (15,062) $ (2,646)
========== ========== ========= ==========
Net income (loss) per common share (Note 6) .......... $ (.37) $ .13 $ (.65) $ (.23)
========== ========== ========= ==========
Weighted average shares outstanding (Note 6) ......... 30,189 31,337 30,136 31,363
========== ========== ========= ==========
The accompanying notes are an integral part of these statements.
</TABLE>
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<TABLE>
SNYDER OIL CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN
STOCKHOLDERS' EQUITY (NOTES 1, 2 AND 6)
(IN THOUSANDS)
<CAPTION>
PREFERRED STOCK COMMON STOCK CAPITAL IN RETAINED
--------------- ---------------- EXCESS OF EARNINGS TREASURY
SHARES AMOUNT SHARES AMOUNT PAR VALUE (DEFICIT) STOCK
------ ------ ------ ------- ---------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1994 .............. 1,035 $ 10 30,209 $ 302 $ 255,961 $ 20,959 $ (2,288)
Common stock grants and
exercise of options .............. - - 138 1 856 - (169)
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) (2,457)
Common stock grants and
exercise of options .............. - - 179 2 1,089 - (258)
Issuance of common .................. - - 399 4 3,689 - -
Repurchase of common ................ - - (640) (6) (6,243) - (795)
Dividends ........................... - - - - (6,173) (4,658) -
Net loss ............................ - - - - - (2,646) -
------ ------ ------ ------ ---------- ---------- --------
Balance, September 30, 1996
(Unaudited) 1,035 $ 10 31,368 $ 314 $ 258,273 $ (36,305) $ (3,510)
====== ====== ====== ====== ========== ========== =========
The accompanying notes are an integral part of these statements.
</TABLE>
5
<PAGE>
<TABLE>
SNYDER OIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (NOTES 1 AND 2)
(IN THOUSANDS)
<CAPTION>
NINE MONTHS ENDED SEPTEMBER 30,
----------------------------------
1995 1996
----------- -----------
(UNAUDITED)
<S> <C> <C>
Operating activities
Net loss ................................................................. $ (15,062) $ (2,646)
Adjustments to reconcile net loss
to net cash provided by operations
Amortization of deferred credits ................................ (1,978) (1,052)
Gains on sales of properties .................................... (11,536) (11,109)
Equity in losses (earnings) of unconsolidated subsidiaries ...... 1,158 (453)
Gain on sales of investments .................................... (371) (4,119)
Exploration expense ............................................. 7,362 2,800
Loss on sale of subsidiary interest ............................. - 15,481
Depletion, depreciation and amortization ........................ 63,201 64,189
Deferred taxes .................................................. (1,711) 317
Changes in current and other assets and liabilities
Decrease (increase) in
Accounts receivable ..................................... 10,961 (6,429)
Inventory and other ..................................... 227 2,838
Increase (decrease) in
Accounts payable ........................................ (8,794) 12,052
Accrued liabilities ..................................... 9,293 585
Other liabilities ....................................... 2,141 (515)
Other ....................................................... 137 86
---------- ----------
Net cash provided by operations ................................. 55,028 72,025
---------- ----------
Investing activities
Acquisition, development and exploration ................................. (83,927) (67,972)
Proceeds from investments ................................................ 4,173 3,328
Outlays for investments .................................................. - (7,093)
Proceeds from sales of properties ........................................ 86,747 45,346
---------- ----------
Net cash realized (used) by investing ........................... 6,993 (26,391)
---------- ----------
Financing activities
Issuance of common ....................................................... 438 748
Repurchase of common stock ............................................... - (7,044)
Repurchase of subordinated notes ......................................... - (4,790)
Decrease in indebtedness ................................................. (53,582) (10,903)
Dividends ................................................................ (10,539) (10,831)
Deferred credits ......................................................... 3,666 (120)
---------- ----------
Net cash used by financing ...................................... (60,017) (32,940)
---------- ----------
Increase in cash .............................................................. 2,004 12,694
Cash and equivalents, beginning of period ..................................... 21,733 27,263
---------- ----------
Cash and equivalents, end of period ........................................... $ 23,737 $ 39,957
========== ==========
Noncash investing and financing activities
Acquisition of stock ..................................................... $ - $ 3,693
The accompanying notes are an integral part of these statements.
</TABLE>
6
<PAGE>
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 minor 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.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Risks and Uncertainties
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. Prices are significantly impacted by the local weather,
production in the area and limited transportation capacity to other regions of
the country. Until recently, mild weather and increased production contributed
to depressed prices. Currently, prices in the region have rebounded sharply,
although it is uncertain if this trend will continue. Increases or decreases in
prices received, particularly in the Rocky Mountains, could have a significant
impact on the Company's future results of operations.
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 Patina Oil & Gas
Corporation ("Patina"). DelMar Petroleum, Inc. ("DelMar") was accounted for in
this manner until all remaining minority interests were acquired in June 1996.
Affiliates in which the Company owns between 20% and 50% are accounted for under
the equity method. Affiliates being accounted for in this manner include Command
Petroleum Limited ("Command"), an Australian affiliate, SOCO Perm Russia, Inc.
("SOCO Perm"), a Russian affiliate, and SOCO Tamtsag Mongolia, Inc. ("SOCO
Tamtsag"), a Mongolian affiliate. Affiliates in which the Company owns less than
20% are accounted for under the cost method. No affiliates are currently
accounted for in this manner. However, the exchange of the Company's investment
in Command (See Note 4) for an investment in Cairn Energy PLC ("Cairn") is
expected to be accounted for in this manner. 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.
Producing Activities
The Company utilizes the successful efforts method of accounting
for its oil and gas properties. Consequently, leasehold costs are capitalized
when incurred. Unproved properties are assessed periodically within specific
geographic areas and impairments in value are charged to expense. During the
three months ended September 30, 1996, the Company provided impairments of $1.5
million. 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
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<PAGE>
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 future abandonment costs
(net of salvage values), are accrued at unit-of-production rates and 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 nine months ended September 30, 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. Accordingly, in the fourth quarter 1995,
the Company provided for $27.4 million in impairments. During the nine months
ended September 30, 1996, the Company did not provide for any significant
impairments.
Foreign Currency Translation Adjustment
Command's functional currency is the Australian dollar. The foreign
currency translation adjustments reported in the balance sheets are the result
of the translation of the Australian dollar balance sheets into United States
dollars at then current exchange rates. As a result of the exchange of the
investment in Command for an investment in Cairn, it is anticipated that this
adjustment will no longer be required.
Section 29 Tax Credits
The Company from time to time enters into arrangements to monetize its
Section 29 tax credits. These arrangements result in revenue increases of
approximately $.40 per Mcf on production volumes from qualified Section 29
properties. As a result of such arrangements, the Company recognized additional
gas revenues of $2.0 million and $1.9 million during the nine months ended
September 30, 1995 and 1996, respectively. These arrangements are expected to
increase revenues through 2002.
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
proportionate share of gas produced. Gas imbalances at December 31, 1995 and
September 30, 1996 were insignificant.
Financial Instruments
The following table sets forth the book value and estimated fair
values of financial instruments:
<TABLE>
<CAPTION>
December 31, September 30,
1995 1996
---------------------- -----------------------
(In thousands)
Book Fair Book Fair
Value Value Value Value
--------- --------- --------- ----------
<S> <C> <C> <C> <C>
Cash and equivalents ............................. $ 27,263 $ 27,263 $ 39,957 $ 39,957
Investments ...................................... 33,220 52,203 43,267 127,850
Senior debt ...................................... (150,001) (150,001) (159,251) (159,251)
Subordinated notes ............................... - - (103,264) (104,238)
Convertible subordinated notes ................... (84,058) (79,997) (80,656) (76,687)
Long-term commodity contracts .................... - 11,623 - 10,038
Interest rate swap ............................... - 107 - (70)
</TABLE>
8
<PAGE>
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 face value
given its floating rate structure. The fair value of the subordinated notes is
estimated based on their price on the New York Stock Exchange.
From time to time, the Company enters into commodity contracts to
hedge the price risk of a portion of its production. Gains and losses on such
contracts are deferred and recognized in income as an adjustment to oil and gas
sales revenue in the period to which the contracts relate. In 1994, the Company
entered into a long-term gas swap arrangement in order to lock in the price
differential between the Rocky Mountain and Henry Hub prices on a portion of its
Rocky Mountain gas production. The contract covers 20,000 MMBtu per day through
2004. In September 1996, that volume represented approximately 15% of the
Company's Rocky Mountain gas production. The fair value of the contract was
based on the market price quoted for a similar instrument.
In September and October 1996, the Company entered into various swap
sales contracts with a weighted average oil price (NYMEX based) of $23.04 for
contract volumes of 645,000 barrels of oil for October 1996 through February
1997. The Company also sold calls for $505,000 on its production of 505,000
barrels of oil for October 1996 through March 1997 at a weighted average oil
price of $23.61 (NYMEX based).
In September 1995, the Company entered into an interest rate swap
covering $50 million of its bank debt. The agreement requires payment to a
counterparty based on a fixed rate of 5.585% and requires the counterparty to
pay the Company interest at the then current 30 day LIBOR rate. Accounts
receivable or payable under this agreement are recorded as adjustments to
interest expense and are settled on a monthly basis. The agreement matures in
September 1997, with the counterparty having the option to extend it for two
years. At September 30, 1996, the fair value of the agreement was estimated at
the net present value discounted at 10%.
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:
<TABLE>
<CAPTION>
December 31, September 30,
1995 1996
------------- -------------
(In thousands)
<S> <C> <C>
SOCO bank facility ....................................... $ 150,001 $ 58,001
Patina bank facilities ................................... - 101,250
Less current portion ..................................... - -
----------- -----------
Senior debt, net ................................. $ 150,001 $ 159,251
=========== ===========
Patina subordinated notes ................................ $ - $ 103,264
=========== ===========
SOCO convertible subordinated notes, net ................. $ 84,058 $ 80,656
=========== ===========
</TABLE>
The Company maintains a $500 million revolving credit facility ("SOCO
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 $125 million at September 30, 1996. Effective November 1, 1996, the
borrowing base was increased to $140 million. The majority of the borrowings
under the facility currently bear interest at LIBOR plus .75% with the
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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
nine months ended September 30, 1996, the average interest rate under the
revolver was 6.3%. 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 $60 million was available for the
payment of dividends and other restricted payments at September 30, 1996.
Simultaneously with the Merger, Patina entered into a bank credit
agreement. The agreement consists of (a) a facility provided to Patina and SOCO
Wattenberg (the "Patina Facility") and (b) a facility provided to GOG (the "GOG
Facility").
The Patina Facility is a revolving credit facility in an aggregate
amount up to $102 million. The amount available for borrowing under the Patina
Facility will be limited to a semiannually adjusted borrowing base that equaled
$102 million at September 30, 1996. Effective November 1, 1996 the borrowing
base was reduced to $85 million. At September 30, 1996, $73.3 million was
outstanding under the Patina Facility. Prior to September 30, 1996, Patina also
had a term loan facility in an amount up to $87 million. This term loan facility
was available to finance purchases of the GOG Subordinated Notes. At September
30, 1996, Patina had not utilized the term loan facility. Accordingly, the term
loan facility was canceled.
The GOG Facility is a revolving credit facility in an aggregate amount
up to $51 million. The amount available for borrowing under the GOG Facility
will be limited to a fluctuating borrowing base that equaled $51 million at
September 30, 1996. Effective November 1, 1996, the borrowing base was reduced
to $35 million. At September 30, 1996, $28 million was outstanding under the
GOG Facility. The GOG Facility was used primarily to refinance GOG's previous
bank credit facility and pay for costs associated with the Merger.
The borrowers may elect that all or a portion of the credit facilities
bear interest at a rate per annum equal to: (i) the higher of (a) prime rate
plus a margin equal to .25% with respect to the GOG Facility and the Patina
Facility (the "Applicable Margin") and (b) the Federal Funds Effective Rate plus
.5% plus the Applicable Margin, or (ii) the rate at which eurodollar deposits
for one, two, three or six months (as selected by the applicable borrower) are
offered in the interbank eurodollar market in the approximated amount of the
requested borrowing (the "Eurodollar Rate") plus 1.25%, with respect to the GOG
Facility and the Patina Facility (the "Eurodollar Margin"). During the period
subsequent to the Merger through September 30, 1996, the average interest rate
under the facilities was 6.9%.
Patina's bank credit agreement contains certain financial covenants,
including but not limited to a maximum total debt to capitalization ratio, a
maximum total debt to EBITDA ratio and a minimum current ratio. The bank credit
agreement also contains certain negative covenants, including but not limited to
restrictions on indebtedness; certain liens; guaranties, speculative derivatives
and other similar obligations; asset dispositions; dividends, loans and
advances; creation of subsidiaries; investments; leases; acquisitions; mergers;
changes in fiscal year; transactions with affiliates; changes in business
conducted; sale and leaseback and operating lease transactions; sale of
receivables; prepayment of other indebtedness; amendments to principal
documents; negative pledge clauses; issuance of securities; and non-speculative
commodity hedging.
Simultaneously with the Merger, Patina recorded $100 million of
Subordinated Notes due July 15, 2004 issued by GOG on July 1, 1994. In
connection with the Merger, Patina also repurchased $1.2 million of the notes.
As part of the purchase accounting, the remaining notes were reflected in the
accompanying financial statements at a market value of $104.6 million or
105.875% of their principal amount. Subsequent to the Merger, an additional $1.3
million of the notes were repurchased by the Company and retired. Interest is
payable each January 15 and July 15. The Notes are redeemable at the option of
GOG, in whole or in part, at any time on or after July 15, 1999, initially at
105.875% of their principal amount, declining to 100% on or after July 15, 2001.
Upon the occurrence of a change of control, as defined in the Notes, GOG would
be obligated to make an offer to purchase all outstanding Notes at a price of
101% of the principal amount thereof. In addition, GOG would be obligated,
subject to certain conditions, to make offers to purchase Notes with the net
cash proceeds of certain asset sales or other dispositions of assets at a price
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<PAGE>
of 101% of the principal amount thereof. The Notes are unsecured general
obligations of GOG and are subordinated to all senior indebtedness of GOG and
to any existing and future indebtedness of GOG's subsidiaries.
The Notes contain covenants that, among other things, limit the
ability of GOG to incur additional indebtedness, pay dividends, engage in
transactions with shareholders and affiliates, create liens, sell assets, engage
in mergers and consolidations and make investments in unrestricted subsidiaries.
Specifically, the Notes restrict GOG from incurring indebtedness (exclusive of
the Notes) in excess of approximately $51 million, if after giving effect to the
incurrence of such additional indebtedness and the receipt and application of
the proceeds therefrom, GOG's interest coverage ratio is less than 2.5:1 or
adjusted consolidated net tangible assets are less than 150% of the aggregate
indebtedness of GOG. GOG currently does not meet the interest coverage ratio
necessary to incur indebtedness in excess of $51 million. The Company is of the
opinion that this will have no materially adverse effect on the Company's
consolidated financial condition.
In 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 $22.57 per share. Given the terms of
the notes, common stock dividends currently reduce the conversion price when
paid. The notes 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. During the third quarter, the Company repurchased $3.8 million of
these notes in accordance with a repurchase program.
Scheduled maturities of indebtedness for the next five years are zero
for the remainder of 1996, 1997 and 1998, $101.3 million in 1999 and $58.0
million in 2000. The long-term portions of the Patina Facilities and SOCO
Facility are scheduled to expire in 1999 and 2000. However, it is management's
policy to renew both the short-term and long-term facilities and extend their
maturities on a regular basis.
Consolidated cash payments for interest were $15.5 million and $13.8
million, respectively, for the nine months ended September 30, 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 these investments:
<TABLE>
<CAPTION>
December 31, 1995 September 30, 1996
------------------------ ---------------------
(In thousands)
Book Fair Book Fair
Value Value Value Value
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Equity method investments $ 30,901 $ 49,884 $ 39,476 $ 124,059
Marketable securities 652 652 - -
Long-term notes receivable 1,667 1,667 3,791 3,791
--------- --------- --------- ---------
$ 33,220 $ 52,203 $ 43,267 $ 127,850
========= ========= ========= =========
</TABLE>
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.
Command Petroleum Limited
Prior to November 6, 1996, the Company had 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
11
<PAGE>
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 an interest in the Fejaj Permit in Tunisia.
The Company will receive an additional 4.7 million shares if a commercial
discovery is made as the result of the initial well. As a result, the Company's
ownership in Command increased to 30.0% and a $1.4 million gain was recognized
during 1995. In June 1996, the Company purchased 8.5 million shares of Command
common stock for $3.6 million, increasing its ownership to 32.6%. The fair value
included in the table above of the Company's investment in Command based on
Command's closing price at September 24, 1996 was $80.4 million, compared to a
book value of $30.5 million. In October 1996, Command announced that it had
completed merger negotiations with Cairn, an international independent oil
company based in Edinburgh, Scotland whose shares are listed on the London Stock
Exchange. On November 6, 1996, the Company announced that it accepted Cairn's
offer for its interest in Command. The Company will receive approximately 16.3
million shares of freely marketable Cairn common shares. Based on Cairn stock
prices and exchange rates at the time the offer was accepted, the fair value of
the Company's investment in Command is estimated to be approximately $90
million. The Company expects to recognize a gain of approximately $60 million in
the fourth quarter of 1996, with no associated current tax liability. However, a
deferred tax provision is expected to be provided in the financial statements.
SOCO Perm Russia, Inc.
In 1993, SOCO Perm was organized by the Company and a U.S. industry
participant. SOCO Perm and a Russian partner, Joint Stock Company, Permneft,
formed the Permtex joint venture to develop proven oil fields in the Volga-Urals
Basin of Russia. To finance a portion of its planned development expenditures,
SOCO Perm closed a private placement of its equity securities with three
industry participants in 1994. As a result, the Company's investment was reduced
from 75% to 41.25% and a $3.5 million net gain was recorded. In 1995, the three
industry participants paid the final installments of their contributions to SOCO
Perm and as a result, the Company recognized an additional gain of $1.1 million.
In April 1996, SOCO Perm closed a private placement which reduced the Company's
investment to 34.91% and indicated a market value of $22.7 million for the
Company's remaining position. The Company recognized a gain in the second
quarter of $2.6 million as a result of this transaction. The private placement
agreement requires SOCO Perm to list its common shares on a securities exchange
during 1998. If such listing does not occur, the new shareholders have the right
to require the Company to purchase their share at a formulated price. The
Company's investment in SOCO Perm had a carrying cost at September 30, 1996 of
$7.1 million.
SOCO Tamtsag Mongolia, Inc.
In 1994, the Company formed a consortium to explore the Tamtsag Basin
of eastern Mongolia, then sold a portion of its interest to three industry
participants. One participant 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 consortium. Accordingly, the Company's
investment in SOCO Tamtsag was reduced from 100% to 49% and a $1.5 million gain
was recognized. In 1996, the Company completed the exchange of a portion of its
interest to an industry participant for consulting services valued at $1.5
million. As a result of this transaction, the Company's ownership was reduced to
42% and an $832,000 gain was recognized. In August 1996, the Mongolian
Parliament ratified the grant of two additional concessions in the area to
Tamtsag Mongolia, bringing the total acreage position to approximately 10
million acres. The Company's investment in SOCO Tamtsag had a carrying cost of
$1.9 million at September 30, 1996 in addition to $2.8 million in mandatory
loans to SOCO Tamtsag which are included in notes receivable in the table above.
The estimated fair value of the Company's investment, based on a recent equity
sale by one of the industry participants to another entity, was approximately
$21.0 million at September 30, 1996.
Domestic Energy Companies
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 of $328,000. The market value of these securities at December
31, 1995 approximated $652,000. During the nine months ended September 30, 1996,
the Company sold all of its remaining investments in these securities for
$968,000 and recognized a corresponding gain of $640,000. In accordance with
SFAS 115 at December 31, 1995, investments were increased by $324,000 of gross
unrealized holding gains, stockholders' equity was increased by $211,000 and
deferred taxes payable were increased by $113,000.
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<PAGE>
Notes Receivable
The Company holds long-term notes receivable due from SOCO Tamtsag and
other privately held corporations with a book value of $1.7 million and $3.8
million at December 31, 1995 and September 30, 1996. The notes from other
privately held corporations 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 the long term. At December 31,
1995 and September 30, 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.
(5) OIL AND GAS PROPERTIES AND GAS FACILITIES
The cost of oil and gas properties at December 31, 1995 and September
30, 1996 includes $24.2 million and $14.0 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:
<TABLE>
<CAPTION>
Nine
Year Ended Months Ended
December 31, September 30,
1995 1996
------------- --------------
(In thousands)
<S> <C> <C>
Proved acquisitions ................................. $ 13,675 $ 231,183
Acreage acquisitions ................................ 7,388 1,794
Development ......................................... 62,578 29,182
Gas processing, transportation and other ............ 7,886 2,506
Exploration ......................................... 8,214 3,109
----------- ----------
$ 99,741 $ 267,774
=========== ==========
</TABLE>
During the nine months ended September 30, 1996, the Company incurred
$231.2 million for domestic proved acquisitions. Of the total acquisition
expenditures, $218.3 million related to an acquisition in May 1996 when the
Company finalized a transaction (the "Merger") whereby the Wattenberg operations
of the Company were consolidated with Gerrity Oil & Gas Corporation ("GOG"). As
a result, the Company retained 70% of the common stock and the former GOG
shareholders received 30% of the common stock of a new public company which is
known as Patina. The Merger was accounted for by Patina as a purchase of GOG. As
the Company owns more than 50% of Patina, it is consolidated into the Company's
financial statements. The Company recognized a net loss of $15.5 million in the
second quarter of 1996 as a result of this transaction. In May 1996, the Company
acquired an incremental interest in certain properties located in the Gulf of
Mexico for a net purchase price of $10.6 million. Subsequent to quarter end, the
Company agreed to acquire a further incremental interest in certain properties
located in the Gulf of Mexico for a gross purchase price of approximately $35
million. These acquisitions are accounted for utilizing the purchase method.
Of the total development expenditures, $8.5 million was concentrated
in the Gulf of Mexico off the coast of Louisiana where four wells were placed on
sales with three in progress at quarter end. The Company expended $6.6 million
in the Piceance Basin of western Colorado to place fifteen wells on sales with
four in progress at quarter end. In the Green River Basin of southern Wyoming,
$6.0 million was incurred to place twelve wells on sales with seven in progress
at quarter end. In the horizontal drilling program in the Giddings Field of
southeast Texas, $3.8 million was incurred to place seven wells on sales with
none in progress at quarter end.
In May 1996, the Company sold a 45% interest in its Piceance Basin
holdings for $22.4 million. The Company recognized a net gain of $2.5 million in
the second quarter as a result of this transaction. In July 1996, the Company
sold a 50% interest in its Green River Basin gas project for $16.7 million. The
Company recognized a net gain of $7.2 million in the third quarter as a result
of this transaction.
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<PAGE>
The following table summarizes the unaudited pro forma effects on the
Company's financial statements assuming significant acquisitions and
divestitures consummated during 1996 (including the Gulf of Mexico acquisition
which was announced subsequent to quarter end and the exchange of Command stock
for Cairn stock which was completed in November 1996) had been consummated on
September 30, 1996 (for balance sheet data) and January 1, 1995 and 1996 (for
statement of operations data). 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.
<TABLE>
<CAPTION>
As of or for
the Nine Months Ended September 30,
-----------------------------------
1995 1996
------------ -----------
(In thousands, except per share data)
<S> <C> <C>
Total assets ...................................................... $ 606,967 $ 844,499
Oil and gas sales ................................................. $ 155,758 $ 157,121
Total revenues .................................................... $ 207,829 $ 191,140
Production direct operating margin ................................ $ 106,950 $ 116,981
Net income (loss) ................................................. $ (17,032) $ 3,800
Net income (loss) per common share ................................ $ (.72) $ (.03)
Weighted average shares outstanding ............................... 30,136 31,363
</TABLE>
(6) STOCKHOLDERS' EQUITY
A total of 75 million common shares, $.01 par value, are authorized of
which 31.4 million were issued at September 30, 1996. The Company also has 2.1
million warrants outstanding. The warrants are exercisable at a price of $21.04
per share. Under the terms of the warrants, common stock dividends not paid out
of retained earnings currently reduce the exercise price when paid and common
stock issuances result in an increase in the number of warrants outstanding. One
million of the warrants expire in each of February 1998 and February 1999. 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. During the nine months ended
September 30, 1996, the Company issued 578,000 shares of common stock, with
399,000 shares issued in exchange for the remaining outstanding stock of DelMar
and 179,000 shares issued primarily for the exercise of stock options. During
the nine months ended September 30, 1996, the Company repurchased 725,000 shares
of common stock for $7.0 million. Quarterly dividends of $.065 per share were
paid in 1995 and the first three quarters of 1996. For book purposes, subsequent
to June 1995, the common stock dividends were in excess of retained earnings and
as such have been 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 quarter
interest in a 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 $20.46 per share. Under the terms of the stock,
common stock dividends not paid out of retained earnings currently reduce the
conversion price when paid. The stock 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 $4.7 million ($1.50 per
6% convertible depositary share per annum), respectively, in preferred dividends
during 1995 and the nine months ended September 30, 1996.
The Company maintains a stock option plan for certain 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 determined by a
committee of independent members of the Board. A stock grant and option plan is
also maintained by the Company whereby each non-employee Director receives 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.
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<PAGE>
Earnings per share are computed by dividing net income, less dividends
on preferred stock, by average common shares outstanding. Net loss applicable to
common for the nine months ended September 30, 1995 and 1996, was $19.7 million
and $7.3 million, respectively. Differences between primary and fully diluted
earnings per share were insignificant for all periods presented.
(7) FEDERAL INCOME TAXES
At September 30, 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 for the nine months ended September 30, 1995 and 1996
follows:
<TABLE>
<CAPTION>
Nine Months Ended September 30,
1995 1996
------------ ------------
<S> <C> <C>
Federal statutory rate .............................................. (35%) (35%)
Loss in excess of net deferred tax liability ........................ 25% 35%
Net change in valuation allowance ................................... - 14%
Alternative minimum taxes ........................................... - 1%
------------ ------------
Effective income tax rate ........................................... (10%) 15%
============ ============
</TABLE>
For tax purposes, the Company had regular net operating loss
carryforwards of $165.5 million and alternative minimum tax loss carryforwards
of $47.7 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 $1.0 million which are available indefinitely. Current income
taxes shown in the financial statements reflect estimates of alternative minimum
taxes.
(8) MAJOR CUSTOMERS
For the nine months ended September 30, 1995, Amoco Production Company
accounted for approximately 11% of revenues. For the nine months ended September
30, 1996, Associated Natural Gas, Inc. accounted for approximately 19% 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) COMMITMENTS AND CONTINGENCIES
The Company rents offices at various locations under non-cancelable
operating leases. Minimum future payments under such leases approximate $503,000
for the remainder of 1996, $2.1 million for 1997, $2.2 million for 1998 and $2.4
million for each of 1999 and 2000.
In April 1995, the Company settled a lawsuit relating to certain
alleged problems at a 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
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 which may be required to resolve the matter, the full amount of the
settlement was expensed in the first quarter of 1995.
In the second quarter 1996, the Company received $1.5 million in
proceeds which was reflected in other revenues related to a judgment involving a
pipeline dispute.
In August 1995, the Company was sued in the United States District
Court of Colorado by 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 various lease provisions.
Substantially all liability under this suit was assumed by Patina upon its
formation. In January 1996, GOG was also sued in a similar but separate action
filed in the Colorado State Court. The plaintiffs allege that the Company
improperly deducted unspecified "post-production" costs in calculating royalty
payments in breach of the relevant lease provisions and that fact was
15
<PAGE>
fraudulently concealed from plaintiffs. The plaintiffs 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 calculations of royalties by it and GOG are and have been
proper under the relevant lease provisions, and they intend to defend these and
any similar suits vigorously. At this time, the Company is unable to estimate
the range of potential loss, if any. 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 results for that period.
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.
16
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
Revenues for the three month and nine month periods ended September 30,
1996 totalled $62.5 million and $161.0 million, respectively. The amounts
represented an increase of 23% and a decrease of less than 1%, as compared to
the respective prior year periods. The revenue increase realized in the third
quarter is the result of an $11.3 million increase (32%) in oil and gas revenues
and a $6.7 million increase in other revenues offset somewhat by a $4.6 million
decline in gas processing, transportation and marketing revenues due to the sale
of the Wattenberg gas facilities in 1995 and a $1.7 million decrease in gains on
sales of properties. The increase in oil and gas revenues can be attributed
primarily to a rise in average price received per equivalent barrel of 26% for
the third quarter to $13.60 compared to $10.81 for the third quarter 1995. In
addition, production increased 5% from the same period in 1995 due to additional
interests acquired in the Gulf of Mexico and the acquisition of Gerrity Oil &
Gas Corporation ("GOG"), offset somewhat by decreased production due to the
property sales which took place beginning in 1995 and the reduction of
development drilling. On May 2, 1996, a transaction was consummated (the
"Merger") whereby the Wattenberg operations of the Company were consolidated
with GOG. As a result, the Company received 70% of the common stock and the
former GOG shareholders received 30% of the common stock of a new public company
known as Patina Oil & Gas Corporation ("Patina"). The Merger was accounted for
by Patina as a purchase of GOG. As the Company owns more than 50% of Patina, it
is consolidated in the Company's financial statements.
Net income for the third quarter of 1996 was $5.6 million as compared
to a net loss of $9.6 million for the same period in 1995. The increase in net
income is primarily attributable to a $11.9 million increase in production
margin, an increase in other revenues of $6.7 million and a decrease in
exploration expense of $3.3 million. However, net income was negatively impacted
by $2.1 million more in depletion, depreciation and amortization expense, $1.8
million more in deferred tax expense, $1.7 million less in gains on sales of
properties, $960,000 less in gross margin from gas processing, transportation
and marketing activities and $558,000 more in interest and other expense. Net
loss per common share for the nine months ended September 30, 1996 was $.23
compared to $.65 in 1995.
Revenues from production operations less direct operating expenses
("production margin") were $33.3 million, above the prior year quarter by $11.9
million or 56%. Average daily production in the third quarter of 1996 was 11,304
barrels and 154 MMcf (37,033 barrels of oil equivalent), a decrease of 2% and an
increase of 8% (5% increase in barrels of oil equivalent), respectively. As
compared to the first quarter 1996, which was subsequent to the 1995
divestitures, but prior to the Merger and an acquisition in the Gulf of Mexico,
production has increased 19% (31,007 barrels of oil equivalent). However, these
increases were offset somewhat by the Company's reduced development schedule in
1996, due to depressed Rocky Mountain gas prices, together with the effects of
continued property sales. Average oil prices increased to $20.25 per barrel
compared to $17.05 received in the third quarter 1995. Natural gas prices
averaged $1.78 per Mcf, a 37% increase from the $1.30 received in third quarter
1995. The increase was primarily attributable to prices finally rebounding in
areas outside of the Rocky Mountain region. Unfortunately, although Patina has
realized increased prices for DJ Basin production during 1996, prices throughout
the greater Rocky Mountain region continued to be severely depressed during the
third quarter. Subsequent to quarter end, prices have rebounded sharply in the
Rocky Mountains, although it is uncertain if this trend will continue. Third
quarter operating expenses per equivalent barrel (including production taxes)
decreased significantly to $3.84 per equivalent barrel as compared to $4.22 in
the comparable 1995 period. This can be primarily attributed to the property
sales in 1995 and 1996 as the sales were concentrated on non-strategic assets
where operating costs were relatively high. The decrease would have been greater
had a significant workover not been necessary in the Gulf of Mexico where an
existing well was converted from a dual zone producer to a single zone producer
in the third quarter of 1996.
The direct operating margin from gas processing, transportation and
marketing activities for the quarter decreased by 57% to $726,000 from $1.7
million in 1995. The decrease resulted primarily from a reduction in processing
margins due to the sale of the Company's Wattenberg gas facilities which was
completed in the third quarter of 1995. The Company realized almost $80 million
in sales proceeds during 1995 on these facilities and recognized a total of $8.7
million in gains.
17
<PAGE>
Gains on sales of properties were $8.0 million for the quarter as
compared to $9.7 million in the prior year quarter. The most significant gain in
the third quarter 1996 resulted in a $7.2 million gain on the sale of a 50%
interest in the Green River Basin holdings for $16.7 million. The remainder of
the gains resulted from small property sales related to the ongoing program to
dispose of non-strategic assets. Other revenues were $3.4 million in the third
quarter of 1996 compared to a charge of $3.2 million in 1995. The 1996 other
revenues consisted primarily of equity in earnings of the Company's Australian
affiliate, Command, and a gain on sale of a partial interest in the Company's
international venture in Mongolia. The charge in 1995 other revenues is
attributed to a $4.0 million impairment recorded related to a security
devaluation.
Exploration expenses in the third quarter 1996 decreased to $2.0
million from $5.3 million in the third quarter 1995. The decrease resulted
primarily from the writeoff of $4.1 million of acreage costs in the third
quarter 1995. Included in the 1996 expenditures of $2.0 million was a $1.2
million dry hole drilled in the Gulf of Mexico in the third quarter on an
unexplored block adjacent to one of the Company's current producing blocks.
General and administrative expenses, net of reimbursements, for third
quarter 1996 were $4.7 million, a 6% decrease from the same period in 1995. The
decrease is primarily attributable to reductions in personnel due to the recent
property divestitures.
Interest and other expense was $7.7 million compared to $7.2 million in
the third quarter 1995. The majority of the increase is the result of a higher
average interest rate primarily due to the Merger which added the Patina
subordinated notes which have an effective interest rate of 11.1% coupled with
an increased average debt balance.
Depletion, depreciation and amortization expense in the third quarter
1996 increased to $24.7 million from $22.5 million in the third quarter 1995.
The increase reflects an increase in the overall depletion, depreciation and
amortization rate per equivalent barrel from $6.96 to $7.24. This increase can
be attributed to downward revisions in reserve quantities primarily in proved
undeveloped reserves which became uneconomic at year end 1995 prices.
DEVELOPMENT, ACQUISITION AND EXPLORATION
During the nine months ended September 30, 1996, the Company incurred
$267.8 million in capital expenditures, including $233.0 million for
acquisitions, $29.2 million for development, $3.1 million for exploration, $1.3
million for field and office equipment and $1.2 million for gas facility
expansion.
The Company expended $233.0 million relating to acquisitions during the
nine months ended September 30, 1996. Of this amount, $231.2 million was for
producing properties and $1.8 million was for acreage purchases. Of the $231.2
million expended for producing properties, $218.3 million related to an
acquisition in May 1996 when the Company finalized the Merger. In May 1996, the
Company acquired an incremental interest in certain properties located in the
Gulf of Mexico for a net purchase price of $10.6 million. Subsequent to quarter
end, the Company agreed to acquire a further incremental interest in certain
properties located in the Gulf of Mexico for approximately $35 million. Of the
total development expenditures, $8.5 million was concentrated in the Gulf of
Mexico off the coast of Louisiana where four wells were placed on sales with
three in progress at quarter end. The Company expended $6.6 million in the
Piceance Basin of western Colorado to place fifteen wells on sales with four in
progress at quarter end. In the Green River Basin of southern Wyoming, $6.0
million was incurred to place twelve wells on sales with seven in progress at
quarter end. In the horizontal drilling program in the Giddings Field of
southeast Texas, $3.8 million was incurred to place seven wells on sales with
none in progress at quarter end.
FINANCIAL CONDITION AND CAPITAL RESOURCES
At September 30, 1996, the Company had total assets of $768.3 million.
Total capitalization was $564.2 million, of which 39% was represented by
stockholder's equity, 28% by senior debt, and 33% by subordinated debt. During
the nine months ended September 30, 1996, net cash provided by operations was
$72.0 million, an increase of 31% compared to 1995. As of September 30, 1996,
commitments for capital expenditures totaled $7.6 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
18
<PAGE>
market conditions. The Company plans to finance its ongoing development
acquisition and exploration expenditures using internally generated cash flow
and existing credit facilities. In addition, joint ventures or future public
offerings of debt or equity securities may be utilized.
As a result of the Merger, the Company has realized increased net cash
provided by operations. For the foreseeable future, cash generated by Patina
will, however, be retained by Patina to fund its development program, reduce
debt and pursue acquisitions in the DJ Basin or elsewhere. Moreover, Patina's
credit facilities currently prohibit the payment of dividends on its common
stock. Accordingly, Patina's cash flow may 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
"SOCO Facility"). The SOCO 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 September 30, 1996
was $125 million. Effective November 1, 1996, the borrowing base was increased
to $140 million. 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 $60 million was available for the payment of dividends
and other restricted payments as of September 30, 1996.
Simultaneously with the Merger, Patina entered into a bank credit
agreement. The agreement consists of (i) a facility provided to Patina and SOCO
Wattenberg (the "Patina Facility") and (ii) a facility provided to GOG (the "GOG
Facility").
The Patina Facility is a revolving credit facility in an aggregate
amount up to $102 million. The amount available for borrowing under the
revolving credit facility will be limited to a semiannually adjusted borrowing
base that equaled $102 million at September 30, 1996. Effective November 1,
1996, the borrowing base was reduced to $85 million. At September 30, 1996,
$73.3 million was outstanding under the revolving credit facility. Prior to
September 30, 1996, Patina also had a term loan facility in an amount up to $87
million. This term loan facility was available to finance purchases of the GOG
Subordinated Notes. At September 30, 1996, Patina had not utilized the term loan
facility. Accordingly, the term loan facility was canceled.
The GOG Facility is a revolving credit facility in an aggregate amount
up to $51 million. The amount available for borrowing under the GOG Facility
will be limited to a fluctuating borrowing base that equaled $51 million at
September 30, 1996. Effective November 1, 1996, the borrowing base was reduced
to $35 million. At September 30, 1996, $28 million was outstanding under the GOG
Facility. The GOG Facility was used primarily to refinance GOG's previous bank
credit facility and pay for costs associated with the Merger.
Patina's bank credit agreement contains certain financial covenants,
including but not limited to a maximum total debt to capitalization ratio, a
maximum total debt to EBITDA ratio and a minimum current ratio. The bank credit
agreement also contains certain negative covenants, including but not limited to
restrictions on indebtedness; certain liens; guarantees, speculative derivatives
and other similar obligations; asset dispositions; dividends, loans and
advances; creation of subsidiaries; investments; leases; acquisitions; mergers;
changes in fiscal year; transactions with affiliates; changes in business
conducted; sale and leaseback and operating lease transactions; sale of
receivables; prepayment of other indebtedness; amendments to principal
documents; negative pledge clauses; issuance of securities; and non-speculative
commodity hedging.
The Company from time to time enters into arrangements to monetize its
Section 29 tax credits. These arrangements result in revenue increases of
approximately $.40 per Mcf on production volumes from qualified Section 29
properties. As a result of such arrangements, the Company recognized additional
gas sales of $2.0 million and $1.9 million during the nine months ended
September 30, 1995 and 1996, respectively. These arrangements are expected to
increase revenues through 2002.
19
<PAGE>
The Company seeks to diversify its exploration and development risks by
seeking partners for its significant development projects and maintains a
program to divest marginal properties and assets which do not fit its long range
plans. During the nine months ended September 30, 1996 the Company received
$45.3 million in proceeds from the sale of oil and gas properties which were
used to reduce debt and finance additional acquisitions in the Gulf of Mexico.
The most significant sale was the sale of a 45% interest in its Piceance Basin
holdings for a sale price of $22.4 million. The Company recognized a net gain of
$2.5 million in the second quarter as a result of this transaction. In addition,
the Company sold a 50% interest in its Green River Basin gas project for $16.7
million. The Company recognized a net gain of $7.2 million in the third quarter
as a result of this transaction.
On November 6, 1996, the Company announced that it accepted an offer
from Cairn Energy PLC ("Cairn") for its interest in Command. The Company will
receive approximately 16.3 million shares of freely marketable Cairn common
shares. Based on Cairn stock prices and exchange rates at the time the offer was
accepted, the fair value of the Company's investment in Command is estimated to
be approximately $90 million. The Company expects to recognize a gain of
approximately $60 million in the fourth quarter of 1996, with no associated
current tax liability. However, a deferred tax provision is expected to be
provided in the financial statements.
During the second quarter, the Board authorized the repurchase of up to
$10 million of the Company's securities and in September 1996, authorized an
additional $10 million for this purpose. During the second and third quarters
the Company repurchased 725,000 common shares for $7.0 million and $3.8 million
face value convertible subordinated notes for $3.5 million. Additional
repurchases may be made at such times and at such prices as the Company deems
appropriate.
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 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.
20
<PAGE>
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 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 for 1995 and for the first nine months of 1996
were increased by $.06 and $.11 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.
<TABLE>
<CAPTION>
Average Prices
--------------------------------------------
Crude Oil
and Natural Equivalent
Liquids Gas Barrels
---------- --------- -----------
(Per Bbl) (Per Mcf) (Per Boe)
<S> <C> <C> <C>
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
Second 20.52 1.62 12.90
Third 20.25 1.78 13.60
</TABLE>
In September 1996, the Company received an average of $21.55 per barrel
and $1.74 per Mcf for its production.
21
<PAGE>
PART II. OTHER INFORMATION
ITEM 4. LEGAL PROCEEDINGS
In September 1996, the Company and other interest owners in a lease in
southern Texas were sued in a case styled LOPEZ, ET AL. V. MOBIL PRODUCING
TEXAS, ET AL. in state court in Brooks County, Texas. The Company's working
interest in the lease is approximately 20%. The complaint alleges, among other
things, that the defendants have failed to pay proper royalties under the lease,
which states that the price upon which royalties for gas production is to be
based on a price that is no less than "the average of the two highest prices
being paid or offered at the time of production for like gas by a pipeline
company to a producer in the area covered by Railroad Commission District
Four...," and have breached their duties to reasonably develop the lease. The
plaintiffs also claim that the defendants have committed fraud and trespassed on
the lease, and demand actual and exemplary damages, attorney's fees and
declaratory relief. Although the complaint does not specify the amount of
damages claimed, an earlier letter from plaintiffs claimed damages in excess of
$50 million. The Company and the other interest owners have filed an answer
denying the claims and intend to contest the suit vigorously.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits -
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) No reports on Form 8-K were filed during the quarter ended September
30, 1996.
22
<PAGE>
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
November 8, 1996
23
<TABLE>
EXHIBIT 12
SNYDER OIL CORPORATION
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(Unaudited)
<CAPTION>
Nine
Months Ended
Year Ended December 31, September 30,
------------------------------------------------ --------------
1991 1992 1993 1994 1995 1996
------ ------- ------- ------ ------- ----------
(Dollars in thousands)
<S> <C> <C> <C> <C> <C> <C>
Income (loss) before taxes, minority
interest and extraordinary item ..... $3,893 $15,027 $22,538 $13,510 ($40,604) ($1,265)
Interest expense ....................... 8,452 4,997 5,315 10,337 21,679 16,769
------ ------- ------- ------- -------- --------
Earnings before taxes, minority
interest, extraordinary item and
fixed charges ....................... 12,345 20,024 27,853 23,847 (18,925) 15,504
====== ======= ====== ======= ======= ========
Fixed Charges:
Interest expense ....................... 8,452 4,997 5,315 10,337 21,679 16,769
------ ------- ------- ------- ------- =======
Total fixed charges .................... $8,452 $4,997 $5,315 $10,337 $21,679 $16,769
====== ======= ====== ======= ======= =======
Ratio of earnings to fixed charges ..... 1.46 4.01 5.24 2.31 (0.87) 0.92
====== ======= ====== ======= ======= =======
</TABLE>
1
<PAGE>
<TABLE>
SNYDER OIL CORPORATION
COMPUTATION OF RATIO OF EARNINGS TO
COMBINED FIXED CHARGES AND PREFERRED DIVIDENDS
(Unaudited)
<CAPTION>
Nine
Months Ended
Year Ended December 31, September 30,
-------------------------------------------------- ---------------
1991 1992 1993 1994 1995 1996
------ ------ ------ ------- ------- ----------
(Dollars in thousands)
<S> <C> <C> <C> <C> <C> <C>
Income (loss) before taxes, minority
interest and extraordinary item ..... $3,893 $15,027 $22,538 $13,510 ($40,604) ($1,265)
Interest expense ....................... 8,452 4,997 5,315 10,337 21,679 16,769
------ ------- ------- ------- ------- ---------
Earnings before taxes, minority
interest, extraordinary item and
fixed charges ....................... 12,345 20,024 27,853 23,847 (18,925) 15,504
====== ======= ====== ======= ======= =======
Fixed Charges:
Interest expense ....................... 8,452 4,997 5,315 10,337 21,679 16,769
Preferred stock dividends .............. 453 4,800 9,100 10,806 6,210 4,658
------ ------- ------- ------- ------- -------
Total fixed charges .................... $8,905 $9,797 $14,415 $21,143 $27,889 $21,427
====== ======= ====== ======= ======= =======
Ratio of earnings
to combined fixed charges
and preferred dividends ............. 1.39 2.04 1.93 1.13 (0.68) 0.72
====== ======= ====== ======= ======= =======
</TABLE>
2
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-mos
<FISCAL-YEAR-END> Dec-31-1996
<PERIOD-START> Jan-01-1996
<PERIOD-END> Sep-30-1996
<CASH> 39,957
<SECURITIES> 0
<RECEIVABLES> 49,504
<ALLOWANCES> 0
<INVENTORY> 5,957
<CURRENT-ASSETS> 99,441
<PP&E> 933,131
<DEPRECIATION> 311,058
<TOTAL-ASSETS> 768,309
<CURRENT-LIABILITIES> 96,252
<BONDS> 343,171
0
10
<COMMON> 314
<OTHER-SE> 220,668
<TOTAL-LIABILITY-AND-EQUITY> 768,309
<SALES> 140,296
<TOTAL-REVENUES> 160,962
<CGS> 100,504
<TOTAL-COSTS> 123,048
<OTHER-EXPENSES> 18,281
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 17,225
<INCOME-PRETAX> (1,265)
<INCOME-TAX> 350
<INCOME-CONTINUING> (2,646)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (2,646)
<EPS-PRIMARY> (.23)
<EPS-DILUTED> (.23)
</TABLE>
