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, 1995
--------------------------------
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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_________________________________________________________
For Quarter Ended September 30, 1995 Commission file number 1-10509
------------------ -------
SNYDER OIL CORPORATION
- --------------------------------------------------------------------
(Exact name of registrant as specified in its charter)
Delaware 75-2306158
------------------------------- ---------------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
777 Main Street, Fort Worth, Texas 76102
- ------------------------------------------ -----------------
(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 [ ].
30,195,985 Common Shares were outstanding as of November 9, 1995
<PAGE>
<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 the results of operations.
<PAGE> 2
<PAGE>
<TABLE>
SNYDER OIL CORPORATION
CONSOLIDATED BALANCE SHEETS (Notes 1 and 2)
(In thousands)
<CAPTION>
December 31, September 30,
1994 1995
-------------- -------------
(Unaudited)
<S> <C> <C>
ASSETS
Current assets
Cash and equivalents $ 21,733 $ 23,737
Accounts receivable 37,055 26,239
Assets held for sale - 16,908
Inventory and other 13,651 13,135
---------- ----------
72,439 80,019
---------- ---------
Investments (Note 4) 43,301 44,199
---------- ---------
Oil and gas properties, successful efforts method (Note 5) 680,215 721,814
Accumulated depletion, depreciation and amortization (207,976) (261,468)
--------- ---------
472,239 460,346
--------- ---------
Gas processing and transportation facilities (Note 5) 106,622 38,662
Accumulated depreciation (21,342) (16,259)
--------- ---------
85,280 22,403
--------- ---------
$673,259 $606,967
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable $ 44,874 $ 36,080
Accrued liabilities 25,112 28,201
Current portion of long term debt (Note 3) 1,745 338
-------- ---------
71,731 64,619
-------- ---------
Senior debt, net (Notes 3) 216,034 162,001
Convertible subordinated notes (Note 3) 83,650 83,956
Capital lease, net (Note 3) 18,823 18,968
Deferred taxes and other (Notes 7 and 9) 3,211 20,419
Minority interest 5,724 4,892
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,
30,209,197 and 30,328,746 issued 302 303
Capital in excess of par value 255,961 256,704
Retained earnings (deficit) 20,959 (4,642)
Common stock held in treasury, 122,018 and 134,191 shares at cost (2,288) (2,457)
Foreign currency translation adjustment 1,222 340
Unrealized gain (loss) on investments (Note 4) (2,080) 1,854
--------- ---------
274,086 252,112
--------- ---------
$673,259 $606,967
========= ==========
<FN>
The accompanying notes are an intergral part of these statements
</TABLE>
<PAGE> 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,
----------------------------- -----------------------------
1994 1995 1994 1995
------------ ------------ ------------ ------------
(Unaudited)
<S> <C> <C> <C> <C>
Revenues (Note 8)
Oil and gas sales $ 33,868 $ 34,998 $100,375 $111,405
Gas processing, transportation and marketing 30,483 9,349 85,481 34,327
Gains on sales of properties (Note 5) - 9,706 1,641 11,536
Other 6,700 (3,214) 11,588 3,730
--------- --------- --------- ---------
71,051 50,839 199,085 160,998
--------- --------- --------- ---------
Expenses
Direct operating 12,932 14,731 36,948 44,448
Cost of gas and transportation 28,117 7,663 75,734 26,136
Exploration 2,265 5,304 4,709 7,362
General and administrative 2,995 3,986 6,872 10,655
Interest and other 3,386 7,161 7,620 21,145
Litigation settlement (Note 10) - - - 4,400
Depletion, depreciation and amortization 18,742 22,540 56,297 63,201
--------- --------- --------- ---------
Income (loss) before taxes and minority interest 2,614 (10,546) 10,905 (16,349)
--------- --------- --------- ---------
Provision for income taxes (Note 7)
Current 25 - 75 25
Deferred 302 (1,120) 302 (1,711)
--------- --------- --------- ---------
327 (1,120) 377 (1,686)
--------- --------- --------- ---------
Minority interest (Note 2) (26) (180) (26) (399)
--------- --------- --------- ---------
Net income (loss) $ 2,261 $ (9,606) $ 10,502 $(15,062)
========= ========= ========= =========
Net income (loss) per common share (Note 6) $ (.02) $ (.37) $ .10 $ (.65)
========= ========= ======== =========
Weighted average shares outstanding (Note 6) 23,688 30,189 23,460 30,136
========= ========= ======== =========
<FN>
The accompanying notes are an integral part of these statements
</TABLE>
<PAGE> 4
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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
Shares Amount Shares Amount Par Value (Deficit)
-------- -------- -------- -------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1993 2,221 $ 22 23,260 $ 233 $ 249,713 $ 25,308
Common stock grants and
exercise of options - - 414 4 2,851 -
Conversion of preferred
to common (1,186) (12) 6,535 65 (53) -
Issuance of warrants - - - - 3,450 -
Dividends - - - - - (16,721)
Net income - - - - - 12,372
-------- -------- -------- -------- ---------- ---------
Balance, December 31, 1994 1,035 10 30,209 302 255,961 20,959
Common stock grants and
exercise of options - - 120 1 743 -
Dividends - - - - - (10,539)
Net loss - - - - - (15,062)
-------- -------- -------- -------- ---------- ---------
Balance, September 30, 1995
(Unaudited) 1,035 $ 10 30,329 $ 303 $ 256,704 $ (4,642)
======== ======== ======== ======== ========== =========
<FN>
The accompanying notes are an integral part of these statements.
</TABLE>
<PAGE> 5
<PAGE>
<TABLE>
SNYDER OIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (Notes 1 and 2)
(In thousands)
<CAPTION>
Nine Months Ended September 30,
----------------------------------
1994 1995
------------- -------------
(Unaudited)
<S> <C> <C>
Operating activities
Net income(loss) $ 10,502 $ (15,062)
Adjustments to reconcile net income (loss) to net cash
provided by operations
Gain on sales of properties (1,641) (11,536)
Exploration expense 4,709 7,362
Depletion, depreciation and amortization 56,297 63,201
Deferred taxes 302 (1,711)
Gain on sale of investments (7,804) (371)
Equity in (earnings) losses (324) 1,158
Amortization of deferred credits (2,335) (1,978)
Changes in operating assets and liabilities
Decrease (increase) in
Accounts receivable 10,795 10,961
Inventory and other (7,372) 227
Increase (decrease) in
Accounts payable 3,021 (8,794)
Accrued liabilities 2,636 9,293
Other liabilities 1,172 2,141
Other 150 137
---------- ----------
Net cash provided by operations 70,108 55,028
---------- ----------
Investing activities
Acquisition, development and exploration (164,102) (83,927)
Proceeds from investments 4,686 4,173
Outlays for investments (8,463) -
Proceeds from sale of properties 1,818 86,747
---------- ---------
Net cash realized (used) by investing (166,061) 6,993
---------- ---------
Financing activities
Issuance of common 942 438
Increase (decrease) in indebtedness 124,406 (53,582)
Debt issuance costs (2,855) -
Dividends (12,520) (10,539)
Deferred credits 2,191 3,666
---------- ----------
Net cash realized (used) by financing 112,164 (60,017)
---------- ----------
Increase in cash 16,211 2,004
Cash and equivalents, beginning of period 10,913 21,733
---------- ----------
Cash and equivalents, end of period $ 27,124 $ 23,737
========== ==========
<FN>
The accompanying notes are an integral part of these statements.
</TABLE>
<PAGE> 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, production, development and exploration of domestic
oil and gas properties. The Company is also involved in gas
processing, transportation, gathering and marketing. The Company is
engaged to a modest but growing extent in international acquisition,
development and exploration and maintains a number of special purpose
subsidiaries which are engaged in ancillary activities including gas
transmission and water disposal. The Company, a Delaware
corporation, is the successor to a company formed in 1978.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
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 in
which the Company owns less than 50% are accounted for under the
equity method.
In 1994, the Company changed from the full cost to the
successful efforts method of accounting for its oil and gas
properties, in order to more accurately reflect its results with the
expansion of its development and exploration efforts. Accordingly,
the consolidated statements of operations for the three months ended
September 30, 1994 and the nine months ended September 30, 1994 have
been restated to conform to successful efforts. The cumulative
effect was to reduce January 1, 1992, retained earnings by $9.5
million. For the 1992 and 1993 years previously reported, the effect
of the accounting change restatement was to reduce net income by $6.0
million ($.27 per share) and $6.1 million ($.26 per share),
respectively. Under successful efforts, oil and gas leasehold costs
are capitalized when incurred. Unproved properties are assessed
periodically on a property-by-property basis and impairments in value
are charged to expense. Exploratory expenses, including geological
and geophysical expenses and delay rentals, are charged to expense as
incurred. Exploratory drilling costs, including stratigraphic test
wells, are initially capitalized, but charged to expense if and when
the well is determined to be unsuccessful. Costs of productive
wells, developmental dry holes 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.
The Company provides an impairment reserve for significant
proved and unproved oil and gas property groups to the extent that
net capitalized costs exceed the undiscounted future value. During
the nine months ended September 30, 1994 and 1995, the Company
provided impairment reserves of $4.7 million and $3.3 million,
respectively.
The Company's investment in its Australian affiliate is
accounted for using the equity method, whereby the cash basis
investment is increased for equity in earnings and decreased for
dividends, if any were received. The affiliate's functional currency
is the Australian dollar. The foreign currency translation
adjustments reported in the balance sheet are the result of the
translation of the Australian dollar balance sheet into United States
dollars at the
balance sheet dates and changes in the exchange rate subsequent to
purchase.
To a limited extent, the Company enters into commodities
contracts to hedge the price risk of a portion of its production. In
1994, the Company entered into certain gas sales arrangements in
order to lock in the price differential between the Rocky Mountain
and the NYMEX Henry Hub prices to reduce exposure to the Rocky
Mountain spot prices. The contracts included 31,000 MMBtu per day
(20,000 MMBtu for a period of ten years and 11,000 MMBtu through July
1995). At December 31, 1994 and September 30, 1995, the net present
<PAGE> 7
<PAGE>
value at 10% of the contracts was estimated to be $4.9 million and
$5.7 million, respectively, with no recorded carrying value.
All liquid investments with a maturity of three months or less
are considered to be cash equivalents. General and administrative
expenses are reduced by reimbursements for well operations, drilling,
management of partnerships and services provided to unconsolidated
affiliates. Reimbursements amounted to $18.1 million and $25.1
million, respectively, for the nine months ended September 30, 1994
and 1995.
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 1994 annual report on Form 10-K.
(3) INDEBTEDNESS
The following indebtedness was outstanding on the respective
dates:
<TABLE>
<CAPTION>
December 31, September 30,
1994 1995
------------- -------------
(In thousands)
<S> <C> <C>
Revolving credit facility $ 216,001 $ 162,001
Other 50 -
------------ -----------
216,051 162,001
Less current portion (17) -
------------ -----------
Senior debt, net $ 216,034 $ 162,001
============ ===========
Convertible subordinated notes, net $ 83,650 $ 83,956
============ ===========
Capital lease 20,551 19,306
Less current portion (1,728) (338)
------------ -----------
Capital lease, net $ 18,823 $ 18,968
============ ===========
</TABLE>
The Company maintains a $500 million revolving credit facility.
The facility is divided into a $400 million long-term portion and a
$100 million short-term portion. The borrowing base available under
the facility at September 30, 1995 was $250 million. In November
1995, the borrowing base will be reduced to $225 million. The
majority of the borrowings under the facility currently bear interest
at LIBOR plus 1% with the remainder at prime, with an option to
select CD plus 1%. The margin on LIBOR or CD decreases to .75% when
the Company's consolidated senior debt becomes less than 80% of its
tangible net worth. During the nine months ended September 30, 1995,
the average interest rate under the revolver was 7.0%. The Company
pays certain fees based on the unused portion of the borrowing base.
Covenants require maintenance of minimum working capital, limit the
incurrence of debt and restrict dividends, stock repurchases, certain
investments, other indebtedness and unrelated business activities.
Such restricted payments are limited by a formula that includes
underwriting proceeds, cash flow and other items. Based on such
limitations, more than $100 million was available for the payment of
dividends and other restricted payments as of September 30, 1995.
In September 1995, the Company entered into an interest rate
swap agreement for a principal amount of $50 million to reduce the
impact of changes in interest rates on its revolving credit facility.
The agreement requires that the Company pay the counterparty interest
at a fixed rate of 5.585%, and requires the counterparty to pay the
Company interest at LIBOR. The agreement matures on September 26,
1997, with the counterparty having the option to extend it for
another two years. At September 30, 1995, the net present value at
10% of the agreement was estimated to be $260,000, with no recorded
carrying value.
<PAGE> 8
<PAGE>
In May 1994, the Company issued $86.3 million of 7% convertible
subordinated notes due May 15, 2001. The net proceeds were $83.4
million. The notes are convertible into common stock at $23.16 per
share, and are redeemable at the option of the Company on or after
May 15, 1997, initially at 103.51% of principal, and at prices
declining to 100% at May 15, 2000, plus accrued interest. At
September 30, 1995, the fair market value of the notes, based on
their closing price on the New York Stock Exchange, was $78.7
million.
In November 1994, the Company entered into an agreement with a
bank whereby the bank purchased the recently constructed West
Wattenberg Gas Plant from the Company for $21 million and leased it
back. The lease has a term of seven years and includes an option to
repurchase the plant at the end of the lease for $4.2 million. As a
capital lease, the asset and related debt are recorded on the balance
sheet of the Company. In June 1995, the Company sold the plant and
certain related assets and relinquished plant operations to the
purchaser. In conjunction with the sale, the lease will remain in
effect until November 1995. At that time, the lease was fully repaid
with additional borrowings under the revolving credit facility. As
a result of the sale, the Company recorded a gain of $515,000, net of
accrued penalties associated with the early lease termination.
Scheduled maturities of indebtedness for the next five years,
after the plant lease payoff, are $338,000 for the remainder of 1995,
zero in 1996 and 1997, $181.0 million in 1998 and zero in 1999. The
long-term portion of the revolving credit facility is scheduled to
expire in 1998; however, it is management's policy to renew the
facility and extend the maturity on a regular basis.
Cash payments for interest were $4.1 million and $15.5 million,
respectively, for the nine months ended September 30, 1994 and 1995.
(4) INVESTMENTS
The Company has investments in foreign and domestic energy
companies and long term notes receivable, which at December 31, 1994
and September 30, 1995, had a book cost of $46.5 million and $42.3
million, respectively. The corresponding fair market values were
$48.2 million and $47.9 million at December 31, 1994 and September
30, 1995, respectively. In 1994, the Company adopted SFAS No. 115,
"Accounting for Certain Investments in Debt and Equity Securities."
Per the pronouncement, investments carried on the cost basis 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 Petroleum Limited
("Command"), an Australian exploration and production company,
accounted for by the equity method. The Sydney based company 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 and 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. The market value of
the Company's investment in Command based on Command's closing price
at September 30, 1995 was $29.2 million, compared to a cost basis of
$25.5 million.
In early 1993, the Company formed the Permtex joint venture 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 investment in the project to three industry
participants in 1994. As a result, its equity basis investment was
reduced from 50% to 20.6% and a $3.5 million net gain was recorded.
In 1995, the three industry participants paid the final installments
of their contributions to the venture and as a result, the Company
recognized an additional gain of $1.1 million. The Russian
investment had a cost and fair value at September 30, 1995 of $4.3
million.
In late 1994, the Company formed a consortium to explore the
Tamtsag Basin of eastern Mongolia. In late 1994 and early 1995, the
Company sold a portion of its investment 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
<PAGE> 9
<PAGE>
participant assigned its exploration rights in the basin to the
venture. Accordingly, the Company's equity basis investment was
reduced from 100% to 49% and had a cost and fair value at September
30, 1995 of $1.5 million. The first well was drilled in second
quarter 1995 and found to be noncommercial. The second well was
spudded in the third quarter and had significant oil shows, but
testing was suspended until the Spring when the proper equipment can
be mobilized.
The Company has investments in securities of publicly traded
domestic energy companies, not accounted for by the equity method,
with a total cost at December 31, 1994 and September 30, 1995 of
$15.4 million and $9.3 million, respectively. The market value of
these securities at December 31, 1994 and September 30, 1995
approximated $12.2 million and $11.2 million, respectively.
Accordingly, at December 31, 1994, investments were decreased by $3.2
million, stockholders' equity was decreased by $2.1 million, and
deferred taxes payable were decreased by $1.1 million, as required by
SFAS No. 115. At September 30, 1995, investments and stockholders'
equity were both increased by $1.9 million, with no adjustment to
deferred taxes.
The Company holds $1.8 million in long term notes receivable due
from privately held corporations. All notes are secured by certain
assets, including stock and oil and gas properties. At December 31,
1994 and September 30, 1995, 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 book value.
(5) OIL AND GAS PROPERTIES AND GAS FACILITIES
The cost of oil and gas properties at December 31, 1994 and
September 30, 1995 includes $23.7 million and $26.6 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,
1994 1995
------------ -------------
(In thousands)
<S> <C> <C>
Acquisition $ 70,255 $ 8,533
Development 156,912 51,808
Gas processing, transportation and other 46,607 6,809
Exploration 5,514 7,520
----------- -----------
$ 279,288 $ 74,670
=========== ===========
</TABLE>
Development expenditures for the nine months ended September 30,
1995 were concentrated primarily in the DJ Basin of Colorado, the
Green River Basin of southern Wyoming, the Giddings Field of
southeast Texas, the Uinta Basin of northeast Utah and the Piceance
Basin of western Colorado. A total of 68 wells were placed on
production in DJ Basin in the first nine months of 1995 with none in
progress at quarter end. In the Green River Basin of southern
Wyoming, 13 wells were placed on sales during 1995 with three in
progress at quarter end. In the horizontal drilling program in the
Giddings Field of southeast Texas, 21 wells were placed on sales in
1995, with three in progress at quarter end. The Uinta Basin
development program in northeast Utah is still in its early stages
with 11 wells placed on sales and three wells abandoned in 1995. In
the Piceance Basin of western Colorado, 6 wells were placed on sales
with none in progress at quarter end.
During the nine months ended September 30, 1995, the Company
expended $8.5 million for domestic acquisitions, of which $5.7
million was for acreage purchases in or around the Company's
operating hubs and $2.8 million for producing properties.
Acquisitions are accounted for utilizing the purchase method. The
pro forma effect of the acquisitions was not material to the
Company's results of operations.
<PAGE> 10
<PAGE>
In June 1995, the Company sold its recently constructed gas
processing plant on the west end of the Wattenberg area of the DJ
Basin along with certain related assets for a sales price of $18.5
million. A net gain of $515,000 was recognized as a result of this
sale. In September 1995, the Company sold the majority of its
remaining Wattenberg gas facilities located in Weld County, Colorado
for a sales price of $60.2 million. A gain of $7.9 million was
recognized as a result of this sale. During the nine months ended
September 30, 1995, the Company also received $8.0 million from sales
of oil and gas properties. Subsequent to quarter end, the Company
entered into definitive agreements to sell certain oil and gas
properties in west Texas and Wyoming for $16.9 million. These
properties have been classified in current assets as being held for
sale in the accompanying balance sheets.
The following tables summarize the unaudited pro forma effects on
the Company's financial statements assuming significant divestitures
consummated during 1995 (including one divestiture which was yet to
be completed as of September 30, 1995) had been consummated as of
January 1, 1994 and 1995. 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>
UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS
For the Year Ended December 31, 1994
(In thousands except per share data)
<CAPTION>
Pro Forma
Pro Forma Divested Interests Interests to be Divested
---------------------------- -----------------------------
Historical Adjustments Combined Adjustments Combined
------------ ------------- ---------- -------------- ----------
<S> <C> <C> <C> <C> <C>
Revenues
Oil and gas sales $ 137,858 $ 137,858 (a) $ (4,240) $ 133,618
Gas processing, transportation and marketing 107,247 (a) (36,435) 70,812 70,812
Gains on sales of properties 1,969 1,969 1,969
Other 15,254 15,254 15,254
----------- ---------- ----------
262,328 225,893 221,653
----------- ---------- ----------
Expenses
Direct operating 50,067 50,067 (a) (2,858) 47,209
Cost of gas and transportation 94,177 (a) (27,103) 67,074 67,074
Exploration 6,505 6,505 6,505
General and administrative 9,053 (a) (1,414) 7,639 (a) (216) 7,423
Interest and other 12,463 (a) (4,344) 8,119 (a) (839) 7,280
Depletion, depreciation and amortization 76,553 (b) (4,649) 71,904 (b) (1,481) 70,423
----------- ---------- ---------
248,818 211,308 205,914
----------- ---------- ---------
Income before taxes and minority interest 13,510 14,585 15,739
Provision for income taxes
Current - - -
Deferred 967 (c) 376 1,343 (c) 404 1,747
---------- ---------- ----------
967 1,343 1,747
---------- ---------- ----------
Minority interest (171) (171) (171)
---------- ---------- ----------
Net income $ 12,372 $ 13,071 $ 13,821
========== ========== ==========
Net income per common share $ 0.07 $ 0.10 $ 0.13
========== ========== ==========
Weighted average shares outstanding 23,704 23,704 23,704
========== ========== ==========
</TABLE>
<PAGE> 11
<PAGE>
<TABLE>
UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS
For the Nine Months Ended September 30, 1995
(In thousands except per share data)
<CAPTION>
Pro Forma
Pro Forma Divested Interests Interests to be Divested
---------------------------- ------------------------------
Historical Adjustments Combined Adjustments Combined
------------ ------------- ---------- -------------- ----------
<S> <C> <C> <C> <C> <C>
Revenues
Oil and gas sales $ 111,405 $ 111,405 (a) $ (4,256) $ 107,149
Gas processing, transportation and marketing 34,327 (a) (22,645) 11,682 11,682
Gains on sales of properties 11,536 (a) (8,451) 3,085 3,085
Other 3,730 3,730 3,730
----------- ---------- ----------
160,998 129,902 125,646
----------- ---------- ----------
Expenses
Direct operating 44,448 44,448 (a) (2,808) 41,640
Cost of gas and transportation 26,136 (a) (18,638) 7,498 7,498
Exploration 7,362 7,362 7,362
General and administrative 10,655 (a) (1,061) 9,594 (a) (213) 9,381
Interest and other 21,145 (a) (3,803) 17,342 (a) (799) 16,543
Litigation settlement 4,400 4,400 4,400
Depletion, depreciation and amortization 63,201 (b) (3,956) 59,245 (b) (3,521) 55,724
----------- ---------- ---------
177,347 149,889 142,548
----------- ---------- ---------
Loss before taxes and minority interest (16,349) (19,987) (16,902)
Provision for income taxes
Current 25 25 25
Deferred (1,711) (1,711) (1,711)
---------- ---------- ---------
(1,686) (1,686) (1,686)
---------- ---------- ---------
Minority interest (399) (399) (399)
---------- ---------- ----------
Net loss $ (15,062) $ (18,700) $ (15,615)
========== ========== ==========
Net loss per common share $ (0.65) (0.78) $ (0.67)
========== ========== ==========
Weighted average shares outstanding 30,136 30,136 30,136
========== ========== ==========
<f/N>
The preceding unaudited pro forma combined statements of operations reflect the following adjustments:
(a) To record the revenue and expense items attributable to the divested interests.
(b) To adjust depletion, depreciation and amortization to the amount which would have been provided.
(c) To adjust income taxes.
</TABLE>
<PAGE> 12
<PAGE>
(6) STOCKHOLDERS' EQUITY
A total of 75 million common shares, $.01 par value, are
authorized of which 30.3 million were issued at September 30, 1995.
In 1994, the Company issued 6,949,000 shares, with 414,000 shares
issued primarily for the exercise of stock options by employees (for
which 122,000 shares were received as consideration in lieu of cash
and are held in treasury) and 6,535,000 shares issued on conversion
of all remaining shares of the 8% preferred. During the nine months
ended September 30, 1995, the Company issued 120,000 shares primarily
for the exercise of stock options by employees (for which 12,000
shares were received as consideration in lieu of cash and are held in
treasury). In 1994, the Company paid first and second quarter
dividends at the rate of $.06 per share and increased the rate to
$.065 per share in the third and fourth quarters. Dividends of $.065
per share were paid for the first three quarters of 1995.
A total of 10 million preferred shares, $.01 par value, are
authorized. In 1991, 1.2 million shares of 8% convertible
exchangeable preferred stock were sold through an underwriting. The
net proceeds were $57.4 million. In 1993, 14,000 of the preferred
shares were converted into 77,000 common shares. Effective December
31, 1994, the remaining 8% convertible preferred shares were
converted into 6,535,000 common shares. In 1993, 4.1 million
depositary shares (each representing a one quarter interest in one
share of $100 liquidation value stock) of 6% preferred stock were
sold through an underwriting. The net proceeds were $99.3 million.
The stock is convertible into common stock at $21.00 per share and is
exchangeable at the option of the Company for 6% convertible
subordinated debentures on any dividend payment date. The 6%
convertible preferred stock is redeemable at the option of the
Company on or after March 31, 1996. The liquidation preference is
$25.00 per depositary share, plus accrued and unpaid dividends. The
Company paid $10.8 million and $4.7 million, respectively, in
preferred dividends during 1994 and the nine months ended September
30, 1995.
The Company maintains a stock option plan for employees providing
for the issuance of options at prices not less than fair market
value. Options to acquire up to three million shares of common stock
may be outstanding at any given time. The specific terms of grant
and exercise are determinable by a committee of independent members
of the Board of Directors. The majority of currently outstanding
options vest over a three-year period (30%, 60%, 100%) and expire
five to seven 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.
At September 30, 1995, a total of 1.8 million options were
outstanding at exercise prices of $6.00 to $20.13 per share. At
September 30, 1995, a total of 778,000 of such options were vested
having exercise prices of $6.00 to $20.13 per share. During 1994,
414,000 options were exercised at prices of $4.53 to $13.00 per
share, and 2,000 were forfeited. During the nine months ended
September 30, 1995, 120,000 options were exercised at prices of $4.53
to $13.00 per share, and 160,000 were forfeited.
Earnings per share are computed by dividing net income, less
dividends on preferred stock, by average common shares outstanding.
Net income (loss) available to common for the nine months ended
September 30, 1994 and 1995, was $2.3 million and ($19.7) million,
respectively. Differences between primary and fully diluted earnings
per share were insignificant for all periods presented.
<PAGE> 13
<PAGE>
(7) FEDERAL INCOME TAXES
At September 30, 1995, the Company had no liability for foreign
taxes. A reconciliation of the United States federal statutory rate
to the Company's effective income tax rate as they apply to the
provision for 1994 and the benefit for 1995 follows:
<TABLE>
<CAPTION>
Nine Months Ended September 30,
-------------------------------
1994 1995
------------ ------------
<S> <C> <C>
Federal statutory rate 35% (35%)
Utilization of net deferred tax (asset) liability (32%) 25%
-------- ---------
Effective income tax rate 3% (10%)
-------- ---------
</TABLE>
The effective tax rate for the nine months ended September 30,
1995 was a benefit of ten percent. This benefit was limited to the
extent of the net deferred tax liability at December 31, 1994 of
$591,000 and the realization of the $1.1 million deferred tax asset
that was previously recorded to stockholders' equity as required by
SFAS No. 115.
For tax purposes, the Company had net operating loss carryforwards
of $162.6 million at December 31, 1994. These carryforwards expire
between 1997 and 2009. At December 31, 1994, the Company had
alternative minimum tax credit carryforwards of $1.4 million and
depletion carryforwards of $1.5 million, both of 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, 1994 and 1995, Amoco
Production Company accounted for approximately 13% and 11%,
respectively, of revenues. Management believes that the loss of any
individual purchaser would not have a material adverse impact on the
financial position or results of operations of the Company.
(9) DEFERRED CREDITS
In 1992, the Company formed a partnership to monetize Section 29
tax credits to be realized from the Company's properties, mainly in
the DJ Basin. Contributions of $3 million were received in 1992,
with $3 million contributed during 1993 and $2.8 million received in
1994. In early 1995, a second investor was added and the limited
partners committed to contribute an additional $5.0 million of which
$2.0 million was received in January 1995 and an additional $2.0
million in August 1995. As a result, this transaction is
anticipated to increase cash flow and net income through 1996. A
revenue increase of more than $.40 per Mcf is realized on production
generated from qualified Section 29 properties in this partnership.
The Company recognized $2.3 million and $2.0 million of this revenue
during the nine months ended September 30, 1994 and 1995,
respectively.
(10) COMMITMENTS AND CONTINGENCIES
The Company rents office space and gas compressors at various
locations under non-cancelable operating leases. Minimum future
payments under such leases approximate $358,000 for the remainder of
1995, $1.5 million for 1996 and 1997, $1.4 million for 1998, and $1.0
million for 1999.
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 plans to vigorously pursue the
non-participating carriers for the great majority of the cost of
settlement. However, given the time period which may be involved in
<PAGE> 14
<PAGE>
resolving the matter, the full amount of the settlement was provided
for in the financial statements in the first quarter of 1995.
In June 1995, the Company recorded $1.5 million as a net
settlement of a dispute involving a gas processing agreement. The
settlement proceeds were received in July 1995.
In August 1995, the Company was served in a class action suit
brought in the United States District Court for the District of
Colorado. The plaintiffs allege themselves to be or to have been
entitled to have received royalty payments and purport 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 lease provisions. The
complaint alleges that the Company has improperly deducted
unspecified "post-production" costs incurred prior to calculating
royalty payments in breach of the relevant lease provisions. The
Company has filed a motion to dismiss the action based on a Colorado
statute that grants exclusive jurisdiction over disputes of the
nature alleged in the complaint to the Colorado Oil and Gas
Conservation Commission. Regardless of the outcome of the motion to
dismiss, the Company believes that costs deducted in calculating
royalties are and have been proper under the relevant lease
provisions, and intends to vigorously defend this and any similar
suits.
In April 1993, the Company was granted a $2.7 million judgment in
litigation involving the allocation of proceeds from a pipeline
dispute. On appeal, the appellate court upheld the verdict but
reduced the judgment to approximately $1.4 million. The judgment may
be further appealed.
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.
<PAGE> 15
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Results of Operations
Effective December 31, 1994, the Company changed its method of
accounting for oil and gas properties from the full cost method to
the successful efforts method. The change was applied retroactively
and prior periods presented have been restated. The following
discussions of operating results are based on those restated amounts.
Total revenues for the three month and nine month periods ended
September 30, 1995 declined to $50.8 million and $161.0 million,
respectively. The amounts represented decreases of 28% and 19% as
compared to the respective prior year periods. The revenue decrease
was primarily the result of the Company's decision to suspend third
party gas marketing until the markets recover. However, oil and gas
sales rose 3% and 11%, respectively, to $35.0 million for the three
months ended September 30, 1995 and $111.4 million for the nine
months ended September 30, 1995. The increase was due to a 13% and
23% increase in equivalent oil and gas production, respectively. The
benefit of these increases did not fully impact revenues as the
average price received per equivalent barrel dropped 9% for the third
quarter and 10% for the nine month period to $10.81 for both periods.
The net loss for the third quarter was $9.6 million as compared to a
$2.3 million net income for the same period in 1994. The decrease
was primarily due to $10 million of non-recurring charges associated
with the write off of certain acreage costs, a provision for expected
losses on various securities, impairments of nonstrategic producing
properties being held for sale and a provision for severance and
restructuring costs. Additional factors were the price decline,
which reduced current quarter revenues by $3.3 million, increased
interest expense and higher depletion, depreciation, and
amortization, partially offset by the continued growth in production.
Net loss per common share for the nine months ended September 30,
1995 was $.65 compared to net income of $.10 in 1994.
Average daily production in the third quarter of 1995 was 11,485
barrels and 142 MMcf (35,201 barrels of oil equivalent), a decrease
of 2% for oil and an increase of 22% for gas, as compared to the
respective prior year periods. The production changes resulted
primarily from the Company's continued development program in 1994
and, to a lesser extent, 1995. During the first nine months of 1995,
an additional 184 wells were placed on production with 12 wells in
various stages of drilling and completion at September 30, 1995. The
gross margin from production operations was $20.3 million, a 3%
decrease from the prior year quarter. Average oil prices of $17.05
per barrel slightly outpaced the $16.21 received in the third quarter
of 1994. However, that modest increase was more than offset by a
continued drastic reduction in gas prices. The average gas price
during the quarter was only $1.30 per Mcf, a 15% decrease from the
$1.53 received in third quarter 1994. Third quarter operating
expenses per equivalent barrel (including production taxes) remained
relatively stable at $4.55 compared to $4.52 for the third quarter of
1994.
The gross margin from gas processing, transportation and marketing
activities decreased by 29% to $1.7 million from $2.4 million in the
same quarter of 1994. The decrease is primarily attributable to the
Company's decision to suspend third party gas marketing until markets
recover and increased operating expenses associated with preparing
the Company's Roggen gas processing facility for increased volumes
after the June sale of the Company's processing plant on the west end
of the Wattenberg area. In September 1995, the Company sold
substantially all of its remaining Wattenberg gas gathering and
processing facilities for $60.2 million and recorded a net gain of
$7.9 million. As part of the sale, the Company entered into an
agreement with the purchaser, which at current pricing, is expected
to provide substantially the same wellhead price as before the sale.
Gains on sales of properties were $9.7 million in the third
quarter of 1995 compared to zero in 1994. The $9.7 million consisted
primarily of the $7.9 million gain from the sale of the Wattenberg
gas gathering and processing facilities. The Company also had
miscellaneous sales of oil and gas properties which resulted in
additional gains of $1.8 million. These asset sales represent the
continuation of the Company's 1995 disposition program which had been
previously disclosed.
<PAGE> 16
<PAGE>
Other income was a negative $3.2 million in the third quarter of
1995 compared to a positive $6.7 million in 1994. The decrease is
attributable to an impairment of $4.0 million in 1995 related to a
security devaluation compared to one time gains recorded in 1994
related to security transactions as a result of domestic stock sales
and sales of equity securities in the Company's international
affiliates.
Exploration costs for the third quarter were $5.3 million compared
to $2.3 million in the prior year quarter. The increase resulted
from a write off of certain exploratory acreage costs.
G&A expenses, net of reimbursements, for third quarter 1995
represented 7.8% of revenues compared to 4.2% for the same period in
1994. The increase is attributable primarily to the decrease in gas
processing, transportation and marketing revenue, a charge for
severance and restructuring costs, and less significantly to an
increase in overhead related to the expanding offshore operations.
Interest and other expense was $7.2 million in 1995 compared to
$3.4 million in the three month period ended September 30, 1994. The
majority of the increase is the result of a rise in outstanding debt
levels, due to the increase in capital expenditure projects, at
higher average interest rates. Senior debt was reduced significantly
after quarter end with the proceeds from the sale of the Wattenberg
gas facilities and the west Texas oil and gas properties
Depletion, depreciation and amortization expense for the third
quarter increased 20% from the same period in 1994. This increase is
primarily due to the 13% increase in production and greater property
impairments as compared to the same period in 1994, offset somewhat
by the production depletion, depreciation and amortization rate of
$5.07 being slightly lower as compared to $5.42 in 1994.
Development, Acquisition and Exploration
During the nine months ended September 30, 1995, the Company
incurred $74.7 million in capital expenditures; including $51.8
million for oil and gas development, $8.5 million for acquisitions,
$5.2 million for gas facility expansion, $7.5 million for exploration
and $1.7 million for field and office equipment.
Of the total development expenditures, $11.3 million was
concentrated in the DJ Basin of Colorado. A total of 68 wells were
placed on production there in the first nine months of 1995 with no
dry holes drilled and none in progress at quarter end. With the
continued declines in gas prices in 1995, the Company has reduced its
DJ Basin drilling plans for the remainder of 1995.
The Company expended $40.5 million for other development and
recompletion projects during the nine months ended September 30,
1995. In the Green River Basin of southern Wyoming, 13 wells were
placed on sales with three in progress at quarter end. In the
horizontal drilling program in the Giddings Field of southeast Texas,
21 wells were placed on sales, with three in progress at quarter end.
The Uinta Basin development program in northeast Utah is still in its
early stages with 11 wells placed on sales and three wells abandoned
in the first nine months of 1995, with none in progress at quarter
end. In the Piceance Basin of western Colorado, 6 wells were placed
on sales, with none in progress at quarter end.
During the nine months ended September 30, 1995, the Company
expended $8.5 million for domestic acquisitions, of which $5.7
million was for acreage purchases in or around the Company's
operating hubs and $2.8 million for producing properties. Although
a number of potential producing property acquisitions are under
review, no individually significant purchases were consummated during
the first nine months of 1995.
The Company's gas gathering and processing facility operations
incurred $5.2 million of capital expenditures in the first nine
months of 1995. The work was concentrated primarily in the
Wattenberg area of DJ Basin, the Piceance Basin in western Colorado,
the Washakie Basin in southern Wyoming and the Giddings Field in
south Texas. In June 1995, the Company sold its recently constructed
gas processing plant on the west end of the Wattenberg area of the DJ
<PAGE> 17
<PAGE>
Basin along with certain related assets for a sales price of $18.5
million. A net gain of $515,000 was recognized as a result of this
sale. In addition, in September 1995, the Company sold substantially
all of its remaining Wattenberg gas gathering and processing
facilities for $60.2 million. A net gain of $7.9 million was
recognized as a result of this sale.
Exploration costs for the nine months ended September 30, 1995
were $7.5 million, primarily for geological and other studies on the
newly acquired domestic undeveloped acreage and the write off of
certain acreage costs. In Russia, commercial production began in mid
1994 with pipeline construction in the southernmost field in the
contract area now completed. Three industry partners committed
$11.25 million to the joint venture to fully fund the western
participants' anticipated equity requirements, of which $8.5 million
was received in 1994 and the remainder received in the second quarter
of 1995. In June 1994, a commitment letter was executed with the
Overseas Private Investment Corporation ("OPIC") whereby OPIC will
commit up to $40 million to the Russian Permtex project. It is
expected that the final OPIC agreement and associated debt financing
will be put in place during 1996, coinciding with the need for
additional funding. The Company is also exploring alternatives to
the OPIC financing, including sales of additional equity interests in
the venture. In Tunisia, an agreement was reached in 1995 whereby
100% of the project was sold to Command for stock for a gain of $1.4
million. The Company will receive additional proceeds if commercial
reserves are discovered on the exploratory well drilled in Tunisia by
Command. In Mongolia, 51% of the properties were sold in 1995 for a
combination of cash and property rights for a gain of $456,000. As
part of the sale, one partner committed to drill two test wells in
Mongolia. One well was drilled in 1995 but proved noncommercial.
The second well was spudded in the third quarter with significant oil
shows, but testing was suspended until next Spring when equipment
could be mobilized.
Financial Condition and Capital Resources
At September 30, 1995, the Company had total assets of $607.0
million. Total capitalization was $537.5 million, of which 47% was
represented by stockholder's equity, 30% by senior debt, 19% by
subordinated debt and the remainder by deferred taxes and other.
During the nine months ended September 30, 1995, net cash provided by
operations was $55.0 million, a decrease of 22% compared to the same
period in 1994. As of September 30, 1995, commitments for capital
expenditures totalled $3.2 million. The Company anticipates that
1995 expenditures for development drilling and gas facilities will
approximate $80 to $100 million. The Company is also actively
pursuing a number of acquisition opportunities which may occur in
1995. The level of these and other future expenditures is largely
discretionary, and the amount of funds devoted to any particular
activity may increase or decrease significantly, depending on
available opportunities and market conditions. The Company plans to
finance its ongoing development, acquisition and exploration
expenditures using internally generated 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.
The Company maintains a $500 million revolving credit facility.
The facility is divided into a $100 million short-term portion and a
$400 million long-term portion that expires on December 31, 1998.
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, 1995 was $250 million. In November 1995,
the borrowing base was reduced to $225 million. The majority of the
borrowings under the facility currently bear interest at LIBOR plus
1% with the remainder at prime. The Company also has the option to
select CD plus 1%. The margin on LIBOR or CD loans decreases to .75%
when the Company's consolidated senior debt becomes less than 80% of
its tangible net worth. Financial covenants limit debt, require
maintenance of minimum working capital and restrict certain payments,
including stock repurchases, dividends and contributions or advances
to unrestricted subsidiaries. Such restricted payments are limited
by a formula that includes underwriting proceeds, cash flow and other
items. Based on such limitations, more than $100 million was
available for the payment of dividends and other restricted payments
as of September 30, 1995.
<PAGE> 18
<PAGE>
In early 1994, the Company executed an agreement with Union
Pacific Resources Corporation ("UPRC") whereby the Company gained the
right to drill wells on UPRC's previously uncommitted acreage in the
Wattenberg area. The transaction significantly increased the
Company's inventory of undeveloped Wattenberg acreage. UPRC retained
a royalty and the right to participate as a 50% working interest
owner in each well, and received warrants to purchase two million
shares of Company stock. On February 8, 1995, the exercise prices
were reset to $21.60 per share and their expiration extended one
year. One million of the warrants expire in February 1998 and the
other million expire in February 1999. For financial reporting
purposes, the warrants were valued at $3.5 million, which was
recorded as an increase to oil and gas properties and capital in
excess of par value. In early 1995, the Company paid UPRC $400,000
for an extension of the time period to drill the commitment wells and
released a portion of the outlying acreage committed to the venture.
In 1992, the Company formed a partnership to monetize Section 29
tax credits to be realized from the Company's properties, mainly in
the DJ Basin. Contributions of $3 million were received in 1992,
with $3 million contributed during 1993 and $2.8 million received in
1994. In early 1995, a second investor was added and the limited
partners committed to contribute an additional $5.0 million, of which
$2.0 million was received in January 1995 and an additional $2.0
million in August 1995. As a result, this transaction is anticipated
to increase cash flow and net income through 1996. A revenue
increase of more than $.40 per Mcf is realized on production
generated from qualified Section 29 properties in this partnership.
The Company recognized $2.3 million and $2.0 million, respectively,
of this revenue during the nine months ended September 30, 1994 and
1995.
The Company maintains a program to divest marginal properties and
assets which do not fit its long range plans. During the nine months
ended September 30, 1994 and 1995, the Company received $1.8 million
and $8.0 million, respectively, in proceeds from sales of oil and gas
properties. Included in the 1995 proceeds are $78.7 million related
to the sales of the Company's Wattenberg gas facilities. Subsequent
to quarter end, the Company announced that it had entered into a
definitive agreement to sell certain properties in west Texas and
Wyoming for $16.9 million.
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.
Inflation and Changes in Prices
While certain of its costs are affected by the general level of
inflation, factors unique to the petroleum industry result in
independent price fluctuations. Over the past five years,
significant fluctuations have occurred in oil and gas prices.
Although it is particularly difficult to estimate future prices of
oil and gas, price fluctuations have had, and will continue to have,
a material effect on the Company.
The following table indicates the average oil and gas prices
received over the last five years and highlights the price
fluctuations by quarter for 1994 and 1995. Average gas prices prior
to 1994 exclude Mississippi gas production sold under a high price
contract. In 1993, the Company renegotiated the gas contract and
received a substantial payment. Average 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.
<PAGE> 19
<PAGE>
<TABLE>
<CAPTION>
Average Prices
--------------------------------------------------------
Crude Oil Per
and Natural Equivalent
Liquids Gas Barrel
---------- --------- ------------
(Per Bbl) (Per Mcf)
<S> <C> <C> <C>
Annual
--------
1990 $ 23.65 $ 1.69 $ 15.61
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
Quarterly
---------
1994
----
First $ 12.02 $ 1.98 $ 11.93
Second 15.55 1.65 12.20
Third 16.21 1.53 11.83
Fourth 15.30 1.56 11.39
1995
----
First $ 16.40 $ 1.31 $ 10.66
Second 17.52 1.29 10.95
Third 17.05 1.30 10.81
</TABLE>
In September 1995, the Company received an average of $16.84 per
barrel and $1.28 per Mcf for its production.
<PAGE> 20
<PAGE>
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
In August 1995, the Company was served in a class action suit
brought in the United States District Court for the District of
Colorado. The plaintiffs allege themselves to be or to have been
entitled to have received royalty payments and purport 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 lease provisions. The
complaint alleges that the Company has improperly deducted
unspecified "post-production" costs incurred prior to calculating
royalty payments in breach of the relevant lease provisions.
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 has filed a motion to dismiss the action based on
a Colorado statute that grants exclusive jurisdiction over disputes
of the nature alleged in the complaint to the Colorado Oil and Gas
Conservation Commission. Regardless of the outcome of the motion to
dismiss, the Company believes that costs deducted in calculating
royalties are and have been proper under the relevant lease
provisions, and intends to defend this and any similar suits
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) Reports on Form 8-K -
No reports on Form 8-K were filed by Registrant during the
quarter ended September 30, 1995.
<PAGE> 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 (James H. Shonsey)
---------------------------------
James H. Shonsey, Vice President
November 14, 1995
<PAGE> 22
<TABLE>
EXHIBIT 12
SNYDER OIL CORPORATION
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(Unaudited)
<CAPTION>
Nine
Years ended December 31, Months Ended
---------------------------------------------------- September 30,
1990 1991 1992 1993 1994 1995
-------- -------- -------- -------- -------- --------
(Dollars in thousands)
<S> <C> <C> <C> <C> <C> <C>
Income (loss) before taxes,
minority interest and
extraordinary item $ 4,154 $ 3,893 $15,027 $22,538 $13,510 ($16,349)
Interest expense 6,273 8,452 4,997 5,315 10,337 17,479
------- ------- ------- ------- ------- ---------
Earnings before fixed charges 10,427 12,345 20,024 27,853 23,847 1,130
======= ======= ======= ======= ======= =========
Fixed Charges:
Interest expense 6,273 8,452 4,997 5,315 10,337 17,479
------- ------- ------- ------- ------- ---------
Total fixed charges $ 6,273 $ 8,452 $ 4,997 $ 5,315 $10,337 $17,479
======= ======= ======= ======= ======= =========
Ratio of earnings to fixed charges 1.66 1.46 4.01 5.24 2.31 .06
to fixed charges ======= ======= ======= ======= ======= =========
</TABLE>
<PAGE> 1
<PAGE>
<TABLE>
SNYDER OIL CORPORATION
COMPUTATION OF RATIO OF EARNINGS TO
COMBINED FIXED CHARGES AND PREFERRED DIVIDENDS
(Unaudited)
<CAPTION>
Nine
Years ended December 31, Months Ended
---------------------------------------------------- September 30,
1990 1991 1992 1993 1994 1995
-------- -------- -------- -------- -------- --------
(Dollars in thousands)
<S> <C> <C> <C> <C> <C> <C>
Income (loss) before taxes,
minority interest and
extraordinary item $ 4,154 $ 3,893 $15,027 $22,538 $13,510 ($16,349)
Interest expense 6,273 8,452 4,997 5,315 10,337 17,479
------- ------- ------- ------- ------- ---------
Earnings before fixed charges 10,427 12,345 20,024 27,853 23,847 1,130
======= ======= ======= ======= ======= =========
Fixed Charges:
Interest expense 6,273 8,452 4,997 5,315 10,337 17,479
Preferred stock dividends 0 453 4,800 9,100 10,806 4,661
------- ------- ------- ------- ------- --------
Total fixed charges $ 6,273 $ 8,905 $ 9,797 $14,415 $21,143 $22,140
======= ======= ======= ======= ======= =========
Ratio of earnings
to combined fixed charges
and preferred dividends 1.66 1.39 2.04 1.93 1.13 .05
======= ======= ======= ======= ======= ========
</TABLE>
<PAGE> 2
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-START> JAN-01-1995
<PERIOD-END> SEP-30-1995
<CASH> 23,737
<SECURITIES> 0
<RECEIVABLES> 26,239
<ALLOWANCES> 0
<INVENTORY> 9,600
<CURRENT-ASSETS> 80,019
<PP&E> 760,476
<DEPRECIATION> 277,727
<TOTAL-ASSETS> 606,967
<CURRENT-LIABILITIES> 64,619
<BONDS> 264,925
<COMMON> 303
0
10
<OTHER-SE> 251,799
<TOTAL-LIABILITY-AND-EQUITY> 606,967
<SALES> 145,732
<TOTAL-REVENUES> 160,998
<CGS> 124,612
<TOTAL-COSTS> 144,440
<OTHER-EXPENSES> 11,762
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 21,145
<INCOME-PRETAX> (16,349)
<INCOME-TAX> (1,686)
<INCOME-CONTINUING> (15,062)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (15,062)
<EPS-PRIMARY> (.65)
<EPS-DILUTED> (.65)
</TABLE>
