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 June 30, 1996
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OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from _________________ to ______________
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Commission file number 1-10509
SNYDER OIL CORPORATION
Delaware 75-2306158
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(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
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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 .
31,439,237 Common Shares were outstanding as of August 12, 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
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<TABLE>
<CAPTION>
SNYDER OIL CORPORATION
CONSOLIDATED BALANCE SHEETS (Notes 1 and 2)
(In thousands)
December 31, June 30,
1995 1996
------------ -------------
(Unaudited)
ASSETS
<S> <C> <C>
Current assets
Cash and equivalents $ 27,263 $ 37,744
Accounts receivable 29,259 48,019
Inventory and other 11,769 11,156
------------- -------------
68,291 96,919
------------- -------------
Investments (Note 4) 33,220 38,483
------------- -------------
Oil and gas properties, successful efforts method (Note 5) 675,961 903,714
Accumulated depletion, depreciation and amortization (240,744) (274,581)
------------- -------------
435,217 629,133
------------- -------------
Gas facilities and other (Note 5) 30,506 33,156
Accumulated depreciation (11,741) (12,464)
------------- -------------
18,765 20,692
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$ 555,493 $ 785,227
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable $ 36,353 $ 55,929
Accrued liabilities 26,096 37,734
----------- ------------
62,449 93,663
----------- ------------
Senior debt, net (Note 3) 150,001 175,297
Senior subordinated notes (Note 3) - 104,617
Convertible subordinated notes (Note 3) 84,058 84,262
Other noncurrent liabilities (Notes 7 and 9) 20,016 17,385
Minority interest 3,601 87,742
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 31,907,637 issued 314 319
Capital in excess of par value 265,911 265,736
Retained earnings (deficit) (29,001) (40,312)
Common stock held in treasury, 134,191 and 250,000 shares at cost (2,457) (3,539)
Foreign currency translation adjustment 380 47
Unrealized investments gains (Note 4) 211 -
----------- ------------
235,368 222,261
----------- ------------
$ 555,493 $ 785,227
=========== ============
The accompanying notes are an integral part of these statements.
</TABLE>
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<TABLE>
<CAPTION>
SNYDER OIL CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS (Notes 1 and 2)
(In thousands except per share data)
Three Months Six Months
Ended June 30, Ended June 30,
------------------------- ------------------------
1995 1996 1995 1996
----------- ----------- ----------- -----------
(Unaudited)
<S> <C> <C> <C> <C>
Revenues (Note 8)
Oil and gas sales $ 38,806 $ 44,330 $ 76,407 $ 80,452
Gas processing, transportation and marketing 11,412 4,344 24,978 8,795
Gains on sales of properties (Note 5) 1,098 3,142 1,830 3,122
Other 5,826 4,952 6,944 6,118
----------- ----------- ----------- ----------
57,142 56,768 110,159 98,487
----------- ----------- ----------- ----------
Expenses
Direct operating 14,522 12,620 27,502 23,379
Cost of gas and transportation 8,444 3,415 18,473 7,111
Exploration 937 290 2,058 804
General and administrative 4,326 2,709 8,884 6,577
Interest and other 7,580 8,886 13,984 13,179
Litigation settlement (Note 10) - - 4,400 -
Loss on sale of subsidiary interest - 15,481 - 15,481
Depletion, depreciation and amortization 20,675 22,745 40,661 39,516
----------- ---------- ----------- ----------
Income (loss) before taxes and minority interest 658 (9,378) (5,803) (7,560)
----------- ---------- ----------- ----------
Provision (benefit) for income taxes (Note 7)
Current - 8 25 33
Deferred - - (591) (335)
----------- ---------- ----------- ----------
- 8 (566) (302)
----------- ---------- ----------- ----------
Minority interest (133) (597) (219) (948)
----------- ---------- ----------- ----------
Net income (loss) $ 525 $ (9,983) $ (5,456) $ (8,206)
============ ========= ========== ==========
Net income (loss) per common share (Note 6) $ (.03) $ (.37) $ (.28) $ (.36)
============ ============ ========== ==========
Weighted average shares outstanding (Note 6) 30,155 31,450 30,109 31,376
============ =========== ========== ==========
The accompanying notes are an integral part of these statements.
</TABLE>
4
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<TABLE>
<CAPTION>
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 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 - - 146 2 875 - (258)
Issuance of common - - 399 4 3,689 - -
Repurchase of common - - (67) (1) (635) - (824)
Dividends - - - - (4,104) (3,105) -
Net loss - - - - - (8,206) -
------- --------- ------- --------- ---------- ---------- --------
Balance, June 30, 1996
(Unaudited) 1,035 $ 10 31,908 $ 319 $ 265,736 $ (40,312) $ (3,539)
======= ========= ======= ========= ========== ========== ========
The accompanying notes are an integral part of these statements.
</TABLE>
5
<PAGE>
<TABLE>
<CAPTION>
SNYDER OIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (Notes 1 and 2)
(In thousands)
Six Months Ended June 30,
----------------------------------
1995 1996
-------------- -------------
(Unaudited)
<S> <C> <C>
Operating activities
Net income (loss) $ (5,456) $ (8,206)
Adjustments to reconcile net income (loss)
to net cash provided by operations
Gains on sales of properties (1,830) (3,122)
Exploration expense 1,993 804
Depletion, depreciation and amortization 40,661 39,516
Deferred taxes (591) (335)
Gain on sales of investments (4,959) (3,195)
Loss on sale of subsidiary interest - 15,481
Equity in losses of unconsolidated subsidiaries 1,338 770
Amortization of deferred credits (1,058) (1,052)
Changes in current and other assets and liabilities
Decrease (increase) in
Accounts receivable (2,974) (4,343)
Inventory and other (339) 1,662
Increase (decrease) in
Accounts payable 2,051 6,305
Accrued liabilities 4,197 3,314
Other liabilities (1,268) (4,939)
Other 98 52
------------- ------------
Net cash provided by operations 31,863 42,712
------------- ------------
Investing activities
Acquisition, development and exploration (66,433) (52,050)
Proceeds from investments 2,467 1,057
Outlays for investments - (4,705)
Proceeds from sales of properties 21,679 25,227
------------- ------------
Net cash used by investing (42,287) (30,471)
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Financing activities
Issuance of common 413 567
Repurchase of common stock - (1,460)
Increase (decrease) in indebtedness 13,733 5,312
Dividends (7,024) (7,209)
Deferred credits 1,780 1,030
------------- ------------
Net cash realized (used) by financing 8,902 (1,760)
------------- ------------
Increase (decrease) in cash (1,522) 10,481
Cash and equivalents, beginning of period 21,733 27,263
------------- ------------
Cash and equivalents, end of period $ 20,211 $ 37,744
============= ============
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 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.
(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 and have been depressed since 1994. In large part, the
decreased prices are the result of mild weather, increased production in the
area and limited transportation capacity to other regions of the country.
Increases or decreases in prices received 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 50% or less 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. 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 June 30, 1996, the Company provided impairments of $1.2
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
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.
7
<PAGE>
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 six months ended June 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. During the six months ended June 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 adjustment reported in the balance sheet is 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 June 30, 1996 were not significant.
Financial Instruments
The following table sets forth the book value and estimated fair
values of the Company's financial instruments:
<TABLE>
<CAPTION>
December 31, June 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 $ 37,744 $ 37,744
Investments 33,220 52,203 38,483 98,562
Senior debt (150,001) (150,001) (175,297) (175,297)
Senior subordinated notes - - (104,617) (104,123)
Convertible subordinated notes (84,058) (79,997) (84,262) (78,919)
Commodity contracts - 11,623 - 15,754
Interest rate swap - 107 - (50)
</TABLE>
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 convertible 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 gas swap arrangement in order to lock in the price differential
between the Rocky Mountain and the NYMEX Henry Hub prices on a portion of its
Rocky Mountain gas production. At June 30, 1996, the long-term contract covered
20,000 MMBtu per day through 2004. In June 1996, that volume represented
approximately 15% of consolidated Rocky Mountain gas production. The fair value
of the contract was based on a market price quoted for a similar instrument.
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
8
<PAGE>
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 June 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, June 30,
1995 1996
----------- ---------
(In thousands)
<S> <C> <C>
SOCO bank facility $150,001 $ 59,001
Patina bank facilities - 116,296
Less current portion - -
-------- -------
Senior debt, net $150,001 $175,297
======== ========
Patina senior subordinated notes $ - $104,617
======== ========
SOCO convertible subordinated notes, net $ 84,058 $ 84,262
======== ========
</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 June 30, 1996. 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 six months ended June 30,
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 $80 million was available for the payment of dividends and other
restricted payments as of June 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 "Company Facility") and (b) a facility provided to GOG (the "GOG
Facility").
The Patina Facility consists of a term loan facility (the "Patina Term
Facility") in an amount up to $87 million and a revolving credit facility (the
"Patina Revolving Facility") in an aggregate amount up to $102 million. The
Patina Term Facility will be available to fund loans from Patina and/or SOCO
Wattenberg to GOG (the "Intercompany Loan") to finance purchases of the GOG
11.75% Senior Subordinated Notes until the first anniversary of the Merger. At
June 30, 1996, Patina had not utilized the Patina Term Facility. The amount
available for borrowing under the Patina Revolving Facility will be limited to a
semiannually adjusted borrowing base that equaled $102 million at June 30, 1996.
At June 30, 1996, $81.8 million was outstanding under the Patina Revolving
Facility.
9
<PAGE>
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 June
30, 1996. At June 30, 1996, $34.5 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
Revolving Facility and .75% increasing by 1% on the first anniversary of the
Merger and by .5% every six months thereafter with respect to the Patina Term
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 Revolving Facility, and 1.5% increasing by 1% on the
first anniversary of the Merger and by .5% every six months thereafter with
respect to the Patina Term Facility (the "Eurodollar Margin"). During the period
subsequent to the Merger through June 30, 1996, the average interest rate under
the facilities was 7.1%.
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 Senior
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 have been reflected in
the accompanying financial statements at a market value of $104.6 million or
105.875% of their principal amount. 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 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 is 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 approximately $51 million primarily
as a result of lower than anticipated commodity prices. The Company is of the
opinion that this will have no materially adverse effect on its financial
condition.
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 $22.70 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, plus accrued interest. Subsequent to quarter end, the Company began
repurchasing a modest amount of these notes in accordance with a repurchase
program authorized by the Board.
10
<PAGE>
Scheduled maturities of indebtedness for the next five years are zero
for the remainder of 1996, 1997 and 1998, $116.3 million in 1999 and $59.0
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 facility and extend the
maturities on a regular basis.
Consolidated cash payments for interest were $11.7 million and $7.6
million, respectively, for the six months ended June 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 June 30, 1996
------------------------ -----------------------
(In thousands)
Book Fair Book Fair
Value Value Value Value
--------- --------- --------- --------
<S> <C> <C> <C> <C>
Equity method investments $ 30,901 $ 49,884 $ 37,453 $ 97,532
Marketable securities 652 652 - -
Long-term notes receivable 1,667 1,667 1,030 1,030
-------- -------- -------- --------
$ 33,220 $ 52,203 $ 38,483 $ 98,562
======== ======== ======== ========
</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.
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. In June 1996, the Company purchased 8.5 million
shares of Command common stock for $3.6 million, increasing its ownership in
Command to 32.6%. The fair value of the Company's investment in Command based on
Command's closing price at June 30, 1996 was $53.8 million, compared to a book
value of $27.6 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 37.5% 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 $7.0
million at June 30, 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 private
placement agreement requires SOCO Perm Russia, Inc. to list its common shares on
a securities exchange during 1997. If such listing does not occur, the new
shareholders have the right to require the Company to purchase their shares at a
formulated price. The Company recognized a gain in the second quarter of $2.6
million as a result of this transaction.
11
<PAGE>
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 June 30, 1996 of $2.9 million. The
fair value of the Company's investment, based on recent equity sales, was
approximately $21.0 million at June 30, 1996. Subsequently, the SOCO consortium
has been granted two additional concessions in the area bringing the total
acreage position to approximately 10 million acres.
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 June 30, 1996 of $328,000 and zero. The market value of
these securities at December 31, 1995 and June 30, 1996 approximated $652,000
and zero. During the six months ended June 30, 1996, the Company sold all of its
remaining investments in these securities for $966,000 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.
The Company holds long-term notes receivable due from privately held
corporations with a book value of $1.7 million and $1.0 million at December 31,
1995 and June 30, 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 June 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 June 30, 1996
includes $24.2 million and $21.0 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>
Six
Year Ended Months Ended
December 31, June 30,
1995 1996
----------- ------------
(In thousands)
<S> <C> <C>
Proved acquisitions $ 13,675 $231,182
Acreage acquisitions 7,388 1,761
Development 62,578 17,680
Gas processing, transportation and other 7,886 1,835
Exploration 8,214 928
-------- --------
$ 99,741 $253,386
======== ========
</TABLE>
During the six months ended June 30, 1996, the Company expended $231.2
million for domestic proved acquisitions. Of the total acquisition expenditures,
$218.3 million related to a noncash 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 owns 70% of the common stock and the former GOG shareholders
own 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, Patina is consolidated into the Company's financial
statements. 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. These acquisitions are accounted for utilizing the purchase method.
Of the total development expenditures, $5.2 million was concentrated in the
Piceance Basin of western Colorado where eleven wells were placed on sales with
two in progress at quarter end. In the Green River Basin of
12
<PAGE>
southern Wyoming, $4.0 million was incurred to place six wells on sales with six
in progress at quarter end. The Company expended $3.2 million offshore in the
Gulf of Mexico, with three wells placed on sales and three wells in progress at
quarter end. In the horizontal drilling program in the Giddings Field of
southeast Texas, $3.7 million was incurred to place six wells on sales with one
in progress at quarter end.
In May 1996, the Company sold a 45% interest in its Piceance Basin holdings
for a gross purchase price of $22 million. The Company recognized a net gain of
$1.8 million in the second quarter as a result of this transaction. Subsequent
to quarter end, the Company sold a 50% interest in its Green River Basin gas
project for a gross sale price of approximately $16.6 million.
The following table summarizes the unaudited pro forma effects on the
Company's financial statements assuming significant acquisitions and
divestitures consummated during 1996 had been consummated on June 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 As of or for
the Six Months the Six Months
Ended June 30, Ended June 30,
1995 1996
-------------- ----------------
(In thousands, except per share data)
<S> <C> <C>
Total assets $ 672,367 $ 775,751
Oil and gas sales $ 104,607 $ 99,269
Total revenues $ 139,307 $ 117,536
Production direct operating margin $ 72,258 $ 72,816
Net income (loss) $ (5,381) $ (7,059)
Net income (loss) per common share $ (.28) $ (.32)
Weighted average shares outstanding 30,109 31,376
</TABLE>
(6) STOCKHOLDERS' EQUITY
A total of 75 million common shares, $.01 par value, are authorized of
which 31.9 million were issued at June 30, 1996. The Company has 2 million
warrants outstanding. The warrants are exercisable at a price of $21.18 per
share. Given the terms of the warrants, common stock dividends currently reduce
the exercise price when paid. 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 six months ended June 30, 1996, the Company issued 545,000
shares of common stock, with 399,000 shares issued in exchange for the remaining
outstanding stock of DelMar and 146,000 shares issued primarily for the exercise
of stock options. During the second quarter 1996, the Company repurchased
152,000 shares of common stock for $1.5 million, 85,000 of which are held in
treasury and the remainder retired. Quarterly dividends of $.065 per share were
paid in 1995 and the first two 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 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 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 $20.59 per share. Given the terms of the stock, common
stock dividends 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
13
<PAGE>
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 $3.1 million ($1.50 per 6% convertible depositary share per
annum), respectively, in preferred dividends during 1995 and the six months
ended June 30, 1996.
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 determined by a
committee of independent members of the Board. 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 loss applicable to
common for the six months ended June 30, 1995 and 1996, was $8.6 million and
$11.3 million, respectively. Differences between primary and fully diluted
earnings per share were insignificant for all periods presented.
(7) FEDERAL INCOME TAXES
At June 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 six months ended June 30, 1995 and 1996
follows:
<TABLE>
<CAPTION>
Six Months Ended June 30,
-------------------------
1995 1996
------- ------
<S> <C> <C>
Federal statutory rate (35%) (35%)
Utilization of net deferred tax asset - 39%
Loss in excess of net deferred tax liability 26% -
------- ------
Effective income tax rate (9%) 4%
======= ======
</TABLE>
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 six months ended June 30, 1995, no purchaser accounted for more
than 10% of revenues. For the six months ended June 30, 1996, Associated Natural
Gas, Inc. accounted for 13% 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 its Section 29 tax
credits. Through May 1996, a revenue increase of more than $.40 per Mcf was
realized on production volumes of approximately 26 Bcf from qualified Section 29
properties in this arrangement. The Company recognized $1.1 million of this
revenue during each of the six month periods ended June 30, 1995 and 1996. In
May 1996, the Company terminated the partnership and simultaneously entered into
a new agreement to monetize its Section 29 tax credits. The new agreement
provides for the Company to receive proceeds from Section 29 tax credits via a
variable production payment. As a result, this arrangement is also expected to
increase revenue by more than $.40 per Mcf through 2002. Patina entered into a
14
<PAGE>
similar arrangement with respect to certain properties contributed to it in the
Merger. Subsequent to quarter end, the Company and Patina each negotiated
agreements whereby additional Section 29 tax credits will be monetized in a
similar structure.
(10) COMMITMENTS AND CONTINGENCIES
The Company rents offices and compressors at various locations under
non-cancelable operating leases. Minimum future payments under such leases
approximate $1.0 million 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 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 which
may be required to resolve the matter, the full amount of the settlement was
expensed in the first quarter of 1995.
In 1993, the Company was granted a $2.7 million judgment involving the
allocation of proceeds from a pipeline dispute. An appellate court upheld the
verdict but reduced the judgment to approximately $1.4 million plus interest.
Proceeds of approximately $1.5 million were received and reflected in other
revenue in April 1996.
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. Substantially all liability under this suit has been
assumed by Patina. In January 1996, GOG was also sued in a similar but separate
action filed in the District Court in and for the City and County of Denver. 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 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, 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.
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
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Results of Operations
Total revenues for the three month and six month periods ended June 30,
1996 declined to $56.8 million and $98.5 million, respectively. The amounts
represented decreases of 1% and 11%, as compared to the respective prior year
periods. The revenue decrease was primarily the result of a $7.1 million and
$16.2 million decline in gas processing, transportation and marketing revenues
due to the sale of the Wattenberg gas facilities in 1995. However, oil and gas
sales rose 14% and 5%, respectively, to $44.3 million for the three months ended
June 30, 1996 and $80.5 million for the six months ended June 30, 1996. The
increase was due to a rise in average price received per equivalent barrel
of 18% for the second quarter and 19% for the six month period to $12.90 and
$12.85, respectively. The benefit of these increases did not fully impact
revenues as equivalent oil and gas production for the second quarter and the six
month period decreased 3% and 11%, respectively, due to the property sales which
took place beginning in 1995 and the reduction of development drilling offset
somewhat by increased production realized due to additional interests acquired
in the Gulf of Mexico and the acquisition of Gerrity Oil & Gas Corporation
("GOG"). On May 2, 1996, a transaction was consummated (the "Merger") whereby
the Wattenberg operations of the Company were consolidated with Gerrity Oil &
Gas Corporation ("GOG"). As a result, the company owns 70% of the common stock
and the former GOG shareholders own 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, Patina is consolidated into the Company's financial statements.
The net loss for the second quarter of 1996 was $10.0 million as
compared to net income of $525,000 for the same period in 1995. The decrease in
net income is primarily attributable to a $15.5 million noncash, nonrecurring
charge related to the Merger in the second quarter 1996, $2.1 million more of
depletion, depreciation and amortization and $2.0 million less of gross margin
from gas processing, transportation and marketing activities in 1996. Net income
was favorably impacted by an increase of $7.4 million in production margin and a
$1.6 million reduction in general and administrative expenses. Net loss per
common share for the six months ended June 30, 1996 was $.36 compared to $.28
in 1995.
Revenues from production operations less direct operating expenses were
$31.7 million, above the prior year quarter by $7.4 million or 31%. Average
daily production in the second quarter of 1996 was 11,180 barrels and 160 MMcf
(37,764 barrels of oil equivalent), a decrease of 13% and an increase of 2% (3%
decrease in barrels of oil equivalent), respectively. However, as compared to
the first quarter of 1996, production has increased 22% (31,007 barrels of oil
equivalent). Production has decreased primarily due to the Company's reduced
development schedule in 1996, due to poor Rocky Mountain gas prices, together
with the effects of property sales. However, these decreases were offset
somewhat by the addition of production from properties acquired in the Merger
and the purchase of additional interests in the Gulf of Mexico. Average oil
prices increased to $20.52 per barrel compared to $17.52 received in the second
quarter of 1995. Natural gas prices averaged $1.62 per Mcf, a 26% increase from
the $1.29 received in second 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 continue to be severely depressed. Second quarter operating expenses per
equivalent barrel (including production taxes) decreased significantly to $3.67
per equivalent barrel as compared to $4.10 in the comparable 1995 period. This
can be primarily attributed to the property sales in 1995 as the sales were
concentrated on non-strategic assets where operating costs were relatively high.
The direct operating margin from gas processing, transportation and
marketing activities for the quarter decreased by 69% to $929,000 from $3.0
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 these facilities
and recognized a total of $8.7 million in gains.
Gains on sales of properties were $3.1 million for the quarter as compared
to $1.1 million in the prior year quarter. The most significant gain in the
second quarter 1996 resulted in a $1.8 million gain on the sale of a 45%
interest in the Piceance Basin holdings for a gross sales price of $22 million.
16
<PAGE>
The remainder of the gains resulted from small property sales related to
the ongoing program to dispose of non-strategic assets. Other income was $5.0
million in the second quarter of 1996 compared to $5.8 million in 1995. The 1996
other income consisted primarily of a gain on sale of a partial interest in the
Company's international venture in Russia and a judgement received pursuant to a
lawsuit.
Exploration expenses in the second quarter 1996 decreased to $290,000
from $937,000 in the second 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 second
quarter 1996 were $2.7 million, a 37% 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 $8.9 million compared to $7.6 million in the
second 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 senior
subordinated notes which have an effective interest rate of 11.1% offset
somewhat by a decreased average debt balance. The loss on sale of subsidiary
interest is the result of the Merger. This loss is a noncash, nonrecurring
charge required under purchase accounting which is the result of the
proportinate share of the historical net book value of the assets contributed to
Patina being greater than the proportinate share of the fair value of the assets
received.
Depletion, depreciation and amortization expense for the second quarter
increased 10% from the same period in 1995. This increase is primarily due to a
higher depletion, depreciation and amortization rate of $5.77 per equivalent
barrel compared to $4.82 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. This
increase was offset somewhat by the 3% decrease in production as compared to
1995. In addition, in the second quarter 1996, $1.2 million of impairment
expense was recognized on certain acreage located primarily in the Giddings
Field of southeast Texas compared to no impairment expense in the second quarter
1995.
Development, Acquisition and Exploration
During the six months ended June 30, 1996, the Company incurred $253.4
million in capital expenditures, including $232.9 million for acquisitions,
$17.7 million for oil and gas development, $997,000 for gas facility expansion,
$928,000 for exploration and $838,000 for field and office equipment.
The Company expended $232.9 million relating to acquisitions during the six
months ended June 30, 1996. Of this amount, $231.2 million was for producing
properties and $1.7 million was for acreage purchases in or around the Company's
operating hubs. Of the $231.2 million expended for producing properties, $218.3
million related to a noncash acquisition in May 1996 when the Company finalized
the Merger. Also, 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.
Of the total development expenditures, $5.2 million was concentrated in
the Piceance Basin of western Colorado where 11 wells were placed on sales with
two in progress at quarter end. In the Green River Basin of southern Wyoming,
$4.0 million was incurred to place six wells on sales with six in progress at
quarter end. The Company expended $3.2 million offshore in the Gulf of Mexico,
with three wells placed on sales and three wells in progress at quarter end. In
the horizontal drilling program in the Giddings Field of southeast Texas, $3.7
million was incurred to place six wells on sales with one in progress at quarter
end.
Financial Condition and Capital Resources
At June 30, 1996, the Company had total assets of $785.2 million. Total
capitalization was $586.4 million, of which 38% was represented by stockholder's
equity, 30% by senior debt, and 32% by subordinated debt. During the six months
ended June 30, 1996, net cash provided by operations was $42.7 million, an
increase of 34% compared to 1995. As of June 30, 1996, commitments for capital
expenditures totaled $8.3 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
17
<PAGE>
decrease significantly, depending on available opportunities and market
conditions. The Company plans to finance its ongoing development, acquisition
and exploration expenditures using internally generated 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 has realized increased
consolidated net cash provided by operations. Cash generated by Patina will,
however, be retained by Patina to fund Patina's development program, reduce debt
levels and pursue additional consolidation opportunities in the DJ Basin.
Moreover, Patina's credit facilities prohibit the payment of dividends on its
common stock. Accordingly, Patina's cash flow will not be available to fund the
Company's other operations or to pay dividends to its stockholders. Since the
date of the Merger, Patina has accounted for approximately 40% of the Company's
consolidated cash provided by operations.
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 June 30, 1996 was
$125 million. In conjunction with the Merger, Patina paid the Company $75
million which was used to reduce the Company's borrowings under the SOCO
Facility. 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 $80 million was available for the payment of dividends and other
restricted payments as of June 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 consists of a term loan facility in an amount up to
$87 million and a revolving credit facility in an aggregate amount up to $102
million. The term loan facility will be available to finance purchases of the
GOG 11.75% Senior Subordinated Notes until the first anniversary of the Merger.
At June 30, 1996, Patina had not utilized the term loan facility. The amount
available for borrowing under the revolving credit facility will be limited to a
semiannually adjusted borrowing base that equaled $102 million at June 30, 1996.
At June 30, 1996, $81.8 million was outstanding under the revolving credit
facility.
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 June
30, 1996. At June 30, 1996, $34.5 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; 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.
In 1992, the Company formed a partnership to monetize its Section 29 tax
credits. Through May 1996, a revenue increase of more than $.40 per Mcf was
realized on production volumes of approximately 26 Bcf from qualified Section 29
properties in this arrangement. The Company recognized $1.1 million of this
revenue during each of the six month periods ended June 30, 1995 and 1996. In
May 1996, the Company terminated the partnership and simultaneously entered into
a new agreement to monetize its Section 29 tax credits. The new agreement
provides for the Company to receive proceeds from Section 29 tax credits via a
variable production payment. As a result, this arrangement is also expected to
increase revenue by more than $.40 per Mcf through 2002. Patina entered into a
18
<PAGE>
similar arrangement with respect to certain properties contributed to it in the
Merger. Subsequent to quarter end, the Company and Patina each negotiated
agreements whereby additional Section 29 tax credits will be monetized in a
similar structure.
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 six months ended June 30, 1996, the Company received $25.2
million in proceeds from the sale of oil and gas properties which were used to
reduce the Company's outstanding senior debt. The most significant sale was the
sale of a 45% interest in its Piceance Basin holdings for a sale price of $22
million. The Company recognized a net gain of $1.8 million in the second quarter
as a result of this transaction. Subsequent to the quarter end, the Company sold
a 50% interest in its Green River Basin gas project for a gross sale price of
approximately $16.6 million.
During the second quarter, the Board authorized the repurchase of up to $10
million of the Company's securities. During the second quarter, the Company
repurchased 152,000 common shares for $1.5 million. Subsequent to quarter end,
the Company has repurchased additional common stock and a modest amount of
convertible subordinated notes. 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.
19
<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 half of 1996 were
increased by $.06 and $.13 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
</TABLE>
In June 1996, the Company received an average of $19.97 per barrel and
$1.57 per Mcf for its production.
20
<PAGE>
PART II. OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security-Holders
The only matter submitted to a vote of the Company's security holders
at the Company's Annual Meeting of Stockholders, held on May 22, 1996, was the
election of directors. All management's nominees for director as listed in the
Company's Proxy Statement were elected with over 98% of votes cast in favor of
each nominee.
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) The following report on Form 8-K was filed during the quarter ended
June 30, 1996:
1. May 17, 1996: Item 2. Acquisition or Disposition of Assets
21
<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 /s/(James H. Shonsey)
---------------------------------
James H. Shonsey, Vice President
August 13, 1996
22
<TABLE>
EXHIBIT 12
SNYDER OIL CORPORATION
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(Unaudited)
<CAPTION>
Six
Year ended December 31, Months Ended
---------------------------------------------------- June 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 ($40,604) ($ 7,560)
Interest expense ................. 8,452 4,997 5,315 10,337 21,679 9,739
-------- -------- -------- -------- -------- --------
Earnings before taxes, minority
interest, extraordinary item and
fixed charges .................. 12,345 20,024 27,853 23,847 (18,925) 2,179
======== ======== ======== ======== ======== ========
Fixed Charges:
Interest expense ................. 8,452 4,997 5,315 10,337 21,679 9,739
-------- -------- -------- -------- -------- --------
Total fixed charges .............. $ 8,452 $ 4,997 $ 5,315 $ 10,337 $ 21,679 $ 9,739
======== ======== ======== ======== ======== ========
Ratio of earnings
to fixed charges ............... 1.46 4.01 5.24 2.31 (.87) .22
======== ======== ======== ======== ======== ========
</TABLE>
1
<PAGE>
<TABLE>
SNYDER OIL CORPORATION
COMPUTATION OF RATIO OF EARNINGS TO
COMBINED FIXED CHARGES AND PREFERRED DIVIDENDS
(Unaudited)
<CAPTION>
Six
Years ended December 31, Months Ended
---------------------------------------------------- June 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) ($7,560)
Interest expense 8,452 4,997 5,315 10,337 21,679 9,739
------- ------- ------- ------- -------- -------
Earnings before taxes, minority
interest, extraordinary item and
fixed charges 12,345 20,024 27,853 23,847 (18,925) 2,179
======= ======= ======= ======= ======== =======
Fixed Charges:
Interest expense 8,452 4,997 5,315 10,337 21,679 9,739
Preferred stock dividends 453 4,800 9,100 10,806 6,210 3,105
------- ------- ------- ------- -------- -------
Total fixed charges $ 8,905 $ 9,797 $14,415 $21,143 $27,889 $12,844
======= ======= ======= ======= ======== =======
Ratio of earnings
to combined fixed charges
and preferred dividends 1.39 2.04 1.93 1.13 (.68) .17
======= ======= ======= ======= ======== =======
</TABLE> 2
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> JUN-30-1996
<CASH> 37,744
<SECURITIES> 0
<RECEIVABLES> 48,019
<ALLOWANCES> 0
<INVENTORY> 6,643
<CURRENT-ASSETS> 96,919
<PP&E> 936,870
<DEPRECIATION> 287,045
<TOTAL-ASSETS> 785,227
<CURRENT-LIABILITIES> 93,663
<BONDS> 364,176
0
10
<COMMON> 319
<OTHER-SE> 221,932
<TOTAL-LIABILITY-AND-EQUITY> 785,227
<SALES> 89,247
<TOTAL-REVENUES> 98,487
<CGS> 63,528
<TOTAL-COSTS> 76,583
<OTHER-EXPENSES> 16,285
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 10,036
<INCOME-PRETAX> (7,560)
<INCOME-TAX> (302)
<INCOME-CONTINUING> (8,206)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (8,206)
<EPS-PRIMARY> (.36)
<EPS-DILUTED> (.36)
</TABLE>
