<PAGE>
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 1996
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ____________ to ____________
Commission file number: 0-9808
PLAINS RESOURCES INC.
(Exact name of registrant as specified in its charter)
AND EACH OF THE SUBSIDIARY GUARANTORS OF $150 MILLION 10.25% SENIOR SUBORDINATED
NOTES DUE 2006 LISTED UNDER "GENERAL" ON PAGE 2 OF THIS REPORT
DELAWARE 13-2898764
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1600 SMITH STREET
HOUSTON, TEXAS 77002
(Address of principal executive offices)
(Zip Code)
(713) 654-1414
(Registrant's telephone number, including area code)
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 ____
----
16,501,195 shares of common stock $.10 par value, issued and outstanding at
November 6, 1996.
Page 1 of 20
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PLAINS RESOURCES INC. AND SUBSIDIARIES
TABLE OF CONTENTS
- --------------------------------------------------------------------------------
GENERAL
This Quarterly Report on Form 10-Q is filed on behalf of Plains Resources
Inc. (the "Company") and the following wholly-owned subsidiaries, which are
guarantors ("Subsidiary Guarantors") of $150 million principal amount of 10.25%
Senior Subordinated Notes due 2006 (the "10.25% Notes").
<TABLE>
<CAPTION>
State or other jurisdictions of I.R.S. Employer
Subsidiary Guarantors incorporation or organization Identification No.
- ---------------------------------------- ------------------------------- ------------------
<S> <C> <C>
Calumet Florida Inc. Delaware 35-1880416
Plains Illinois Inc. Delaware 76-0487569
Plains Marketing & Transportation Inc. Delaware 76-0339476
Plains Resources International Inc. Delaware 76-0040974
PRI Producing Inc. Delaware 73-1197243
PLX Crude Lines Inc. Delaware 76-0387477
PLX Ingleside Inc. Delaware 76-0493777
Plains Terminal & Transfer Corporation Delaware 76-0376679
Stocker Resources, Inc. California 33-0421175
Stocker Resources, L.P. California 33-0430755
</TABLE>
PAGE
PART I. FINANCIAL INFORMATION
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:
Condensed Consolidated Balance Sheets:
September 30, 1996 and December 31, 1995......................... 3
Condensed Consolidated Statements of Operations:
For the three and nine months ended September 30, 1996 and 1995.. 4
Condensed Consolidated Statements of Cash Flows:
For the nine months ended September 30, 1996 and 1995............ 5
Notes to Condensed Consolidated Financial Statements.............. 6
Separate financial statements of Calumet Florida Inc., Plains Illinois Inc.,
Plains Marketing & Transportation Inc., Plains Resources International Inc., PRI
Producing Inc., PLX Crude Lines Inc., PLX Ingleside Inc., Plains Terminal &
Transfer Corporation, Stocker Resources, Inc., and Stocker Resources, L.P., as
Subsidiary Guarantors of the 10.25% Notes, have not been included herein because
(a) such guarantors are jointly and severally liable for full and unconditional
guarantees of the 10.25% Notes and (b) the aggregate earnings of such guarantors
and the Company are equivalent, and the aggregate net assets and equity of such
guarantors and the Company are substantially equivalent, to the net assets,
earnings and equity of the Company on a consolidated basis.
MANAGEMENT'S DISCUSSION AND ANALYSIS............................. 9
PART II. OTHER INFORMATION...................................... 18
Page 2 of 20
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PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (in thousands, except share data)
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
1996 1995
-------------- ------------------
(unaudited)
<S> <C> <C>
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 625 $ 6,129
Accounts receivable and other 79,336 52,383
Inventory 6,977 5,120
--------- ---------
Total current assets 86,938 63,632
--------- ---------
PROPERTY AND EQUIPMENT
Oil and natural gas properties - full cost method:
Subject to amortization 360,344 328,712
Not subject to amortization 51,665 48,795
Downstream assets, primarily crude oil terminal and storage facility 34,966 32,788
Other property and equipment 7,872 7,789
--------- ---------
454,847 418,084
Less allowance for depreciation, depletion and amortization (152,605) (137,546)
--------- ---------
302,242 280,538
--------- ---------
DEFERRED INCOME TAXES, NET 10,190 --
OTHER ASSETS 10,337 7,876
--------- ---------
$ 409,707 $ 352,046
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and other current liabilities $ 89,535 $ 56,573
Interest payable 1,091 3,977
Royalties payable and drilling advances 6,745 6,364
Notes payable and other current obligations 521 1,467
--------- ---------
Total current liabilities 97,892 68,381
BANK DEBT 66,100 98,000
SUBORDINATED DEBT 149,107 100,000
OTHER LONG-TERM DEBT 3,578 7,089
OTHER LONG-TERM LIABILITIES 2,170 1,547
--------- ---------
318,847 275,017
--------- ---------
STOCKHOLDERS' EQUITY
Common stock, $.10 par value, 50,000,000 shares authorized;
issued and outstanding 16,426,816 at September 30, 1996,
and 16,178,670 shares at December 31, 1995 1,643 1,618
Additional paid-in capital 119,684 118,090
Accumulated deficit (30,467) (42,679)
--------- ---------
90,860 77,029
--------- ---------
$ 409,707 $ 352,046
========= =========
</TABLE>
See notes to condensed consolidated financial statements.
Page 3 of 20
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PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)
(in thousands, except per share data)
- -------------------------------------------------------------------------------
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------------- ---------------------
1996 1995 1996 1995
-------- -------- --------- ---------
<S> <C> <C> <C> <C>
REVENUE
Oil and natural gas sales $ 24,825 $ 15,136 $ 70,597 $ 45,614
Marketing, transportation and storage 144,321 88,354 377,871 246,632
Interest and other income 99 117 220 264
-------- -------- --------- ---------
169,245 103,607 448,688 292,510
-------- -------- --------- ---------
EXPENSES
Production expenses 9,902 7,253 28,533 21,160
Purchases, transportation and storage 141,727 86,610 370,826 241,794
General and administrative 1,899 1,753 5,941 5,527
Depreciation, depletion and amortization 5,632 4,113 16,053 12,238
Interest expense 4,274 3,395 12,806 10,075
Litigation settlement -- -- 4,000 --
-------- -------- --------- ---------
163,434 103,124 438,159 290,794
-------- -------- --------- ---------
Income before income taxes and extraordinary item 5,811 483 10,529 1,716
Income tax expense (benefit) 2,325 -- (6,787) --
-------- -------- --------- ---------
INCOME BEFORE EXTRAORDINARY ITEM 3,486 483 17,316 1,716
EXTRAORDINARY ITEM:
(Loss) on early extinguishment of debt, net of tax benefit 1,515 -- (5,104) --
-------- -------- --------- ---------
NET INCOME $ 5,001 $ 483 $ 12,212 $ 1,716
======== ======== ========= =========
Net income per common and common equivalent share:
Before extraordinary item $ 0.20 $ 0.03 $ 0.98 $ 0.10
Extraordinary item 0.08 -- (0.29) --
-------- -------- --------- ---------
$ 0.28 $ 0.03 $ 0.69 $ 0.10
======== ======== ========= =========
Weighted average number of common and common equivalent shares 17,821 16,174 17,578 15,951
======== ======== ========= =========
</TABLE>
See notes to condensed consolidated financial statements.
Page 4 of 20
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PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited) (in thousands)
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
-----------------------------
1996 1995
--------- ---------
<S> <C> <C>
NET CASH PROVIDED BY OPERATING ACTIVITIES $ 26,669 $ 14,585
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from the sale of oil and natural gas properties 3,066 1,827
Payment for acquisition, exploration and development costs (36,506) (16,885)
Payment for additions to other property and assets (1,876) (887)
--------- ---------
Net cash used in investing activities (35,316) (15,945)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt 217,323 23,750
Principal payments of long-term debt (208,357) (20,359)
Costs incurred to redeem long-term debt (6,468) --
Proceeds from exercise of stock options 1,619 545
Other (974) 1,204
--------- ---------
Net cash provided by financing activities 3,143 5,140
--------- ---------
Net (decrease) increase in cash and cash equivalents (5,504) 3,780
Cash and cash equivalents, beginning of period 6,129 1,291
--------- ---------
Cash and cash equivalents, end of period $ 625 $ 5,071
========= =========
</TABLE>
See notes to condensed consolidated financial statements
Page 5 of 20
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 1996
(UNAUDITED)
NOTE 1--ACCOUNTING POLICIES
The accompanying unaudited condensed consolidated financial statements have been
prepared in accordance with the instructions to interim financial reporting as
prescribed by the Securities and Exchange Commission ("SEC"). For further
information, refer to the consolidated financial statements and notes thereto
included in the Company's Annual Report on Form 10-K for the year ended December
31, 1995, filed with the SEC.
All material adjustments consisting only of normal recurring adjustments which,
in the opinion of management, were necessary for a fair statement of the results
for the interim periods, have been reflected. Certain reclassifications have
been made to the prior year statements to conform with the current year
presentation. The Company evaluates the capitalized costs of its oil and
natural gas properties on an ongoing basis and has utilized the most recently
available information to estimate its reserves at September 30, 1996, in order
to determine the realizability of such capitalized costs. Future events,
including drilling activities, product prices and operating costs, may affect
future estimates of such reserves.
NOTE 2 -- LONG-TERM DEBT AND EXTRAORDINARY LOSS ON EARLY EXTINGUISHMENT
On March 19, 1996, the Company sold $150 million of Senior Subordinated Notes
due 2006, Series A, bearing a coupon rate of 10.25% (the "Series A 10.25%
Notes"). Such notes were issued pursuant to a Rule 144A private placement at
approximately 99.38% to yield 10.35%. On August 8, 1996, the Company exchanged
a total of $149.5 million principal amount of the Series A 10.25% Notes for
10.25% Senior Subordinated Notes due 2006, Series B, (the "Series B 10.25%
Notes"). The Series B 10.25% Notes are substantially identical (including
principal amount, interest rate, maturity and redemption rights) to the Series A
10.25% Notes for which they were exchanged, except for certain transfer
restrictions relating to the Series A 10.25% Notes.
The Series A 10.25% Notes and the Series B 10.25% Notes (collectively, the
"10.25% Notes") are redeemable, at the option of the Company, on or after March
15, 2001 at 105.13%, at decreasing prices thereafter prior to March 15, 2004,
and thereafter at 100% plus, in each case, accrued interest to the date of
redemption. In addition, prior to March 15, 1999, up to $45 million in
principal amount of the 10.25% Notes are redeemable at the option of the
Company, in whole or in part, from time to time, at 110.25% of the principal
amount thereof, with the Net Proceeds of any Public Equity Offering (as both are
defined in the indenture under which the 10.25% Notes were issued (the
"Indenture")).
The Indenture contains covenants including, but not limited to the following:
(i) limitations on incurrence of additional indebtedness; (ii) limitations on
certain investments; (iii) limitations on restricted payments; (iv) limitations
on disposition of assets; (v) limitations on dividends and other payment
restrictions affecting subsidiaries; (vi) limitations on transactions with
affiliates; (vii) limitations on liens; and (viii) restrictions on mergers,
consolidations and transfers of assets. In the event of a Change of Control and
a corresponding Rating Decline, as both are defined in the Indenture, the
Company will be required to make
Page 6 of 20
<PAGE>
an offer to repurchase the 10.25% Notes at 101% of the principal amount thereof,
plus accrued and unpaid interest to the date of the repurchase. The 10.25%
Notes are unsecured general obligations of the Company and are subordinated in
right of payment to all existing and future senior indebtedness of the Company
and are guaranteed by all of the Company's principal subsidiaries.
Proceeds from the sale of the 10.25% Notes, net of offering costs, were
approximately $144.6 million and were used to redeem the Company's 12% Senior
Subordinated Notes due 1999 (the "12% Notes") at 106% of the $100 million
principal amount outstanding and to retire bridge bank indebtedness which was
incurred in December 1995 in connection with the acquisition of certain oil
properties. The 12% Notes were redeemed on April 18, 1996, and the Company has
recognized an extraordinary loss of $8.5 million, $5.1 million net of deferred
tax benefit, in connection therewith (See Note 4). Prior to redemption, the 12%
Notes had an average remaining life of three years and scheduled maturities of
$50 million in each of 1998 and 1999.
In April 1996, the Company's revolving credit facility (the "Revolving Credit
Facility") and borrowing base thereunder was increased to $125 million from $75
million. The Revolving Credit Facility, as amended, matures on May 1, 1998, at
which time the remaining outstanding balance converts to a term loan which is
repayable in twenty equal quarterly installments commencing August 1, 1998. The
Revolving Credit Facility bears interest, at the option of the Company, at
either LIBOR plus 1.75% or Base Rate (as defined therein) plus .375%. Final
maturity of the Revolving Credit Facility occurs on May 1, 2003. The Revolving
Credit Facility is guaranteed by all of the Company's principal subsidiaries and
is secured by the oil and gas properties of the Company and its subsidiaries and
the stock and personal property of all subsidiary guarantors. At September 30,
1996, the Company had $66.1 million in borrowings and a $1 million standby
letter of credit outstanding under the Revolving Credit Facility.
NOTE 3 -- LITIGATION SETTLEMENT
The Company and certain of its officers and directors and a former director and
officer were named in two class action lawsuits filed in 1992 and 1993 seeking
an aggregate of approximately $90 million in compensatory damages and punitive
damages in an unspecified amount for alleged violations of the federal
securities laws and state common law arising out of certain alleged
misrepresentations and omissions in the Company's disclosure regarding its
onshore natural gas exploration activities. On March 6, 1996, the Company
announced that it had notified the court that a settlement in principle had been
reached in such cases. Under the terms of the settlement, the plaintiffs agreed
to dismiss all claims against the Company and its officers and directors in
exchange for a cash payment of approximately $6.25 million. Taking into account
prior costs incurred by the Company to defend these suits, this settlement
resulted in a charge to 1996 first quarter earnings of $4 million. By Order and
Final Judgment entered on September 30, 1996, the Court approved the Stipulation
of Settlement and the settlement amount was paid on November 1, 1996.
Approximately $4.1 million of such amount was paid by the Company's insurance
carrier and $2.2 million was paid by the Company.
Page 7 of 20
<PAGE>
NOTE 4 -- INCOME TAXES
During the first quarter of 1996, the Company reversed $11 million of the $18.3
million valuation allowance which was reserved against its net deferred tax
asset of $18.3 million. Accordingly, a credit to deferred income tax expense of
$11 million was reflected in the first quarter of 1996. As of September 30,
1996, the valuation allowance was approximately $7.3 million.
The reversal of the valuation allowance was due to management's belief that the
benefits derived from the net deferred tax asset will be realized prior to their
expiration. This assessment is based on the cumulative progress made by the
Company over the last three years to reduce unit expenses, increase gross
margins and substantially increase its production and proved reserves through
its acquisition and exploitation activities. This assessment was further
confirmed during the first quarter of 1996 with the sale of the Series A 10.25%
Notes, which enhanced the Company's financial flexibility and provided
additional liquidity, achievement of substantial expense reductions on a
significant property acquired late in the fourth quarter of 1995 and results of
drilling and exploitation activities. Management believes that its current oil
and natural gas properties and its downstream marketing and crude oil storage
and terminalling activities provide lower risk opportunities to generate taxable
income which can be offset by the tax net operating loss carryforwards which
comprise a significant portion of the net deferred tax asset. Despite the
significant turnaround achieved over the last three years and the current
outlook for profitability, due to the uncertainties in the oil and gas industry,
including but not limited to forecasting production, proved reserves, product
prices, production expenses and similar events beyond management's control,
there can be no assurance that the Company will generate any earnings or
specific level of continuing earnings.
For the nine months ended September 30, 1996, the Company recognized a net
deferred tax benefit before extraordinary item of $6.8 million. Such amount
consists of a $4.2 million deferred tax provision on the Company's income before
extraordinary item and the $11 million valuation allowance reduction previously
discussed. In addition, the Company reported a $3.4 million deferred tax
benefit reported as an extraordinary item. Such deferred tax benefit is
attributable to the first quarter extraordinary loss from the redemption of the
12% Notes (See Note 2).
NOTE 5 -- EARNINGS PER SHARE
Earnings per share is based on the weighted average number of common and common
equivalent shares of Common Stock outstanding. Common equivalent shares include
employee stock options and warrants.
Page 8 of 20
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Three month periods ended September 30, 1996 and 1995
For the quarter ended September 30, 1996, the Company reported net income before
extraordinary item of $3.5 million, or $.20 per share, on total revenue of
$169.2 million. This compares with net income of $.5 million, or $.03 per
share, on total revenue of $103.6 million for the third quarter of 1995. Net
income after extraordinary item was $5.0 million, or $.28 per share. Cash flow
from operations (net income plus noncash expenses) more than doubled, increasing
149% to $11.4 million as compared to $4.6 million in the third quarter of 1995.
Earnings before interest, taxes, depreciation, depletion and amortization
("EBITDA") was $15.7 million, nearly double the $8.0 million in the 1995
comparative quarter. The improvement in operating results is primarily
attributable to increased oil production and expanded unit operating margins in
the upstream segment and continued growth in the downstream segment.
The following table sets forth certain operating information of the Company for
the periods presented:
THREE MONTHS ENDED
SEPTEMBER 30,
----------------------------------
1996 1995
---------------- ----------------
(in thousands, except per unit data)
(unaudited)
AVERAGE DAILY PRODUCTION VOLUMES
BARRELS OF OIL EQUIVALENT ("BOE")
LA Basin (91% oil) 9.4 8.3
S. Florida (100% oil) 5.1 3.6
Illinois Basin (100% oil) 3.5 --
Other properties -- 0.8
------ ------
Total (95% oil) 18.0 12.7
====== ======
AVERAGE SALES PRICE
Per barrel of oil $15.46 $13.72
====== ======
Per mcf of natural gas $ 1.11 $ 0.94
====== ======
UNIT ECONOMICS
Average sales price per BOE $14.97 $12.94
Production expenses per BOE 5.97 6.20
------ ------
Gross margin per BOE 9.00 6.74
Upstream G&A expenses per BOE 0.72 0.98
------ ------
Gross profit per BOE $ 8.28 $ 5.76
====== ======
Oil and natural gas production for the third quarter of 1996 increased 42% to
1.66 million BOE, as compared to the 1.17 million BOE produced in last year's
comparative quarter. The Company's unit gross margin increased to $9.00 per
BOE, a 34% improvement over the $6.74 per BOE recorded in last year's third
quarter. Unit gross profit, which deducts all pre-interest cash costs
attributable to the upstream segment, was $8.28 per BOE, up 44% over 1995's
third quarter amount of $5.76 per BOE.
Page 9 of 20
<PAGE>
The significant increase in production volumes is attributable to the Company's
acquisition and exploitation activities. As a result of exploitation activities
conducted in the first nine months of 1996, average net daily production from
the Company's LA Basin properties increased to approximately 9,400 BOE per day,
up 1,100 BOE per day, or 13% over last year's comparative quarter. Net
production from the Company's South Florida Sunniland Trend properties increased
approximately 43% to average 5,100 barrels of oil per day in the third quarter
of 1996 as compared to 3,600 barrels per day in last year's third quarter. The
current quarter average incorporates the impact of production from the Company's
development well drilled at the Raccoon Point Field. This well was completed
and placed on line in late March. Daily gross production from this well during
the third quarter averaged approximately 3,100 barrels of oil with an oil cut of
around 85%. The Company owns a 100% working interest and an 84% net revenue
interest in this well.
The quarter to quarter comparisons of production volumes and unit margins were
affected by sales of nonstrategic properties and the acquisition of the
Company's Illinois Basin properties in the fourth quarter of 1995. Net
production attributable to properties sold totaled 77,000 BOE or an average of
over 800 BOE per day during the 1995 third quarter. Net production from the
Illinois Basin properties totaled 316,000 barrels of oil or an average of 3,500
barrels of oil per day during the third quarter of 1996. The Illinois Basin
properties have higher unit production expenses and also receive higher oil
price realizations against the benchmark NYMEX index price than the Company's
other properties.
Oil and natural gas revenues increased 64% to $24.8 million for the third
quarter of 1996 due to increased production volumes and higher average product
prices. The Company's average product price, which represents a combination of
fixed and floating price sales arrangements and incorporates location and
quality discounts from the benchmark NYMEX prices, increased 16% to $14.97 per
BOE. The increased product price is primarily attributable to the higher
quality Illinois Basin production, a reduction in the quality and location
differential for the South Florida Sunniland Trend production, the December 1995
purchase of a production payment which previously burdened the price on the
Company's LA Basin production, and the impact on the Company's floating price
barrels of increased crude oil prices. Financial swap arrangements and futures
transactions entered into by the Company to hedge production are included in the
foregoing product prices. Such transactions had the effect of decreasing the
Company's average price per BOE by $2.68 and $.10 in the third quarter of 1996
and 1995, respectively.
During the current year quarter, the NYMEX benchmark price averaged $22.35 per
barrel, up 26% as compared to an average of $17.75 per barrel in the correlative
period of 1995. Although the impact of higher commodity prices on the Company's
results was substantially mitigated due to preexisting hedges, this commodity
price increase over the prior year period, as well as strong demand for crude
oil, had a positive impact on net income before extraordinary item of
approximately $1.2 million and approximately $2.0 million on cash flow and
EBITDA in the third quarter of 1996. Of this $2.0 million, approximately $1.75
million is related to the unhedged production in the upstream segment and
approximately $.25 million is related to the Company's downstream activities.
Approximately 73% of the Company's third quarter of 1996 oil production was
hedged at an average NYMEX benchmark price of around $18.00 per barrel.
The Company's downstream segment reported gross margin (marketing,
transportation and storage revenues less purchases, transportation and storage
expenses) of $2.6 million for the third quarter of 1996, reflecting an
approximate 49% increase over the $1.7 million reported for the 1995 quarter.
Gross revenues were $144.3 million and $88.4 million for the respective periods.
Gross profit (gross margin less downstream general and administrative ("G&A")
expenses) increased 67% to $1.9 million versus $1.1 million in the third quarter
of 1995. Such results are directly attributable to the continued expansion of
the downstream segment's base level activities and strong market demand for
crude oil during the third quarter
Page 10 of 20
<PAGE>
of 1996. Total average daily crude oil volumes marketed and terminalled during
the 1996 third quarter were 56,000 barrels and 53,000 barrels, respectively.
Such amounts represent respective increases of 22% and 43% as compared with
average daily volumes of 46,000 barrels and 37,000 barrels in last year's third
quarter.
Aggregate unit production expenses declined 4% to $5.97 per BOE versus $6.20 per
BOE in the third quarter of 1995. The reduction is attributable to decreases in
the company's LA Basin and Sunniland Trend properties which have a component of
fixed production costs that do not increase with incremental production. Such
reductions were partially offset by the addition of the higher cost Illinois
Basin production. Total production expenses increased to $9.9 million from $7.3
million for the third quarter of 1995 primarily due to the acquisition of the
Illinois Basin properties.
The Company extended its three-year trend of reducing unit G&A expenses as
upstream unit G&A expenses decreased 27% to $.72 per BOE as compared to $.98 per
BOE in last year's comparative quarter. Such decrease is primarily due to
increased production volumes. Total G&A expenses, including downstream
activities, were $1.9 million for the three months ended September 30, 1996,
compared to $1.8 million for the 1995 period. The increase is primarily
attributable to increased expenses associated with the Company's downstream
activities.
Depreciation, depletion and amortization ("DD&A") expense increased to $5.6
million from $4.1 million reported in the third quarter of 1995 due primarily to
higher production volumes. The Company's DD&A rate was $3.00 per BOE in both
quarters.
Interest expense for the quarter ended September 30, 1996, increased to $4.3
million from $3.4 million for the comparative prior year quarter primarily due
to higher outstanding debt which was partially offset by a lower overall average
interest rate. Capitalized interest was $.9 million and $.8 million for the
three months ended September 30, 1996 and 1995, respectively.
During the third quarter, the Company recognized a deferred tax provision of
$2.3 million. The Company also recognized a $1.5 million deferred tax benefit
reported as an extraordinary item. Such deferred tax benefit is attributable to
the first quarter extraordinary loss from the early redemption of the Company's
$100 million of 12% Senior Subordinated Notes due 1999 (the "12% Notes").
Nine month periods ended September 30, 1996 and 1995
For the nine months ended September 30, 1996, the Company reported net income
before nonrecurring items of $10.3 million, or $.59 per share, on total revenue
of $448.7 million. This compares with net income of $1.7 million, or $.10 per
share, on total revenue of $292.5 million for the first nine months of 1995.
Cash flow from operations (net income plus noncash expenses) was $30.6 million,
more than double the $14.0 million reported in the 1995 period. EBITDA
increased 81% to $43.4 million as compared to $24.0 million in the first nine
months of 1995. Cash flow and EBITDA are also presented before the nonrecurring
items. Net cash provided by operating activities, as reported in the condensed
consolidated statements of cash flows, increased to $26.7 million for the nine
months ended September 30, 1996, as compared to $14.6 million for the 1995
comparative period. The improvement in operating results is primarily
attributable to increased oil production and expanded unit operating margins in
the upstream segment and continued growth in the downstream segment.
Nonrecurring items include an $8.5 million extraordinary loss associated with
the early redemption of the 12% Notes ($5.1 million net of tax), a $4.0 million
charge related to the settlement of a four year old lawsuit and an $11.0 million
tax benefit related to the reversal of a portion of the valuation reserve
against
Page 11 of 20
<PAGE>
the Company's net deferred tax asset. After giving effect to such nonrecurring
items, the Company reported net income for the first nine months of 1996 of
$12.2 million, or $.69 per share. Before extraordinary items, net income was
$17.3 million or $.98 per share.
The following table sets forth certain operating information of the Company for
the periods presented:
NINE MONTHS ENDED
SEPTEMBER 30,
----------------------------------
1996 1995
---------------- ----------------
(in thousands, except per unit
data)
(unaudited)
AVERAGE DAILY PRODUCTION VOLUMES
BARRELS OF OIL EQUIVALENT
LA Basin (91% oil) 9.1 8.3
S. Florida (100% oil) 4.5 3.5
Illinois Basin (100% oil) 3.5 --
Other properties 0.1 1.0
------ ------
Total (95% oil) 17.2 12.8
====== ======
AVERAGE SALES PRICE
Per barrel of oil $15.58 $13.88
====== ======
Per mcf of natural gas $ 0.89 $ 1.02
====== ======
UNIT ECONOMICS
Average sales price per BOE $15.02 $13.07
Production expenses per BOE 6.07 6.06
------ ------
Gross margin per BOE 8.95 7.01
Upstream G&A expenses per BOE 0.80 1.06
------ ------
Gross profit per BOE $ 8.15 $ 5.95
====== ======
Oil and natural gas production for the first nine months of 1996 increased 35%
to 4.70 million BOE versus the 3.49 million BOE produced in the 1995 comparative
period. The Company's unit gross margin increased to $8.95 per BOE, a 28%
improvement over the $7.01 per BOE recorded in last year's period. Unit gross
profit, which deducts all pre-interest cash costs attributable to the upstream
segment, was $8.15 per BOE, up 37% over 1995's nine month average of $5.95 per
BOE.
The significant increase in production volumes is attributable to the Company's
acquisition and exploitation activities. As a result of exploitation activities
conducted in the first nine months of 1996, average net daily production from
the Company's LA Basin properties for the nine months ended September 30, 1996,
increased to approximately 9,100 BOE per day, up 800 BOE per day, or 10% over
last year's comparative period. Net production from the Company's South Florida
Sunniland Trend properties increased approximately 28% to average 4,500 barrels
of oil per day in the first nine months of 1996 as compared to 3,500 barrels per
day in last year's comparative period. The current year South Florida Sunniland
Trend average incorporates the impact of production from the Company's
development well drilled at the Raccoon Point Field. This well was completed and
placed on line in late March and since such time daily gross production from
this well has averaged approximately 3,100 barrels of oil (2,600 net to the
Company).
Page 12 of 20
<PAGE>
The period to period comparisons of production volumes and unit margins were
affected by sales of nonstrategic properties and the acquisition of the
Company's Illinois Basin properties in the fourth quarter of 1995. Net
production attributable to properties sold totaled 256,000 BOE or an average of
just under 1,000 BOE per day during the first nine months of 1995. Net
production from the Illinois Basin properties totaled 948,000 barrels of oil or
an average of 3,500 barrels of oil per day during the first nine months of 1996.
Oil and natural gas revenues increased 55% to $70.6 million for the first nine
months of 1996 due to increased production volumes and higher average product
prices. The Company's average product price, which represents a combination of
fixed and floating price sales arrangements and incorporates location and
quality discounts from the benchmark NYMEX prices, increased 15% to $15.02 per
BOE. The increased product price is primarily attributable to the higher
quality Illinois Basin production, a reduction in the quality and location
differential for the South Florida Sunniland Trend production, the December 1995
purchase of a production payment which previously burdened the price on the
Company's LA Basin production, and the impact on the Company's floating price
barrels of increased crude oil prices. Financial swap arrangements and futures
transactions entered into by the Company to hedge production are included in the
foregoing product prices. Such transactions (which do not include fixed price,
physical delivery arrangements) had the effect of decreasing the Company's
average price per BOE by $1.94 and $.26 in the first nine months of 1996 and
1995, respectively.
During the current year, the NYMEX benchmark price averaged approximately $21.15
per barrel, up 14% as compared to an average of $18.48 in the correlative period
of 1995. Although the impact of higher commodity prices on the Company's
results was substantially mitigated due to preexisting hedges, this commodity
price increase over the prior year period, as well as strong demand for crude
oil, had a positive impact on net income before extraordinary item of
approximately $2.2 million and approximately $3.7 million on cash flow and
EBITDA for the nine months ended September 30, 1996. Of this $3.7 million,
approximately $3.1 million is related to the unhedged production in the upstream
segment and approximately $.6 million is related to the Company's downstream
activities. Approximately 69% of the Company's oil production was hedged during
the first nine months of 1996 at an average NYMEX benchmark price of around $18
per barrel.
The Company's downstream segment reported gross margin (marketing,
transportation and storage revenues less purchases, transportation and storage
expenses) of $7.0 million for the nine months ended September 30, 1996,
reflecting an approximate 46% increase over the $4.8 million reported for the
1995 period. Gross revenues were $377.9 million and $246.6 million for the
respective periods. Gross profit (gross margin less downstream G&A expenses)
increased 62%, totaling $4.9 million versus $3.0 million in first nine months of
last year. Such results are directly attributable to continued expansion of the
downstream segment's base level activities and strong market demand for crude
oil during 1996. Total average daily crude oil volumes marketed and terminalled
during the nine months ended September 30, 1996 were 57,000 barrels and 55,000
barrels, respectively. Such amounts represent respective increases of 27% and
45% as compared with average daily volumes of 45,000 barrels and 38,000 barrels
in last year's nine month period.
Primarily as a result of the higher cost Illinois Basin production, aggregate
unit production expenses for the first nine months of 1996 increased slightly to
$6.07 per BOE. Unit production expenses for the Illinois Basin properties,
which averaged $12.00 per barrel in the fourth quarter of 1995, averaged
approximately $8.53 per barrel for the 1996 nine-month period. The significant
reduction in production expenses for the Illinois Basin properties is a result
of operational modifications implemented throughout 1996. The overall increase
in unit production expenses attributable to the Illinois Basin properties was
offset by decreases in unit production expenses in the Company's other core
areas. Unit production expenses for the LA Basin
Page 13 of 20
<PAGE>
properties were $6.19 per BOE for the first nine months of 1996, or 6% lower
than last year's comparative period. Unit production expenses for the South
Florida Sunniland Trend properties averaged $3.98 per BOE, approximately 20%
lower than the 1995 average of $4.97 per BOE. These reductions are primarily
attributable to increased production from fields with a component of fixed
production costs which do not increase with incremental production and to
reimbursements received in the second quarter of 1996 for electricity
overcharges in the previous year. Total production expenses increased to $28.5
million from $21.2 million for the first nine months of 1995 primarily due to
the acquisition of the Illinois Basin properties.
The Company extended its three-year trend of reducing unit G&A expenses as
upstream unit G&A expenses decreased 25% to $.80 per BOE as compared to $1.06
per BOE in last year's nine month period. Such decrease is primarily due to
increased production volumes. Total G&A expenses, including downstream
activities, were $5.9 million for the nine months ended September 30, 1996,
compared to $5.5 million for the 1995 period. The increase is primarily
attributable to increased expenses associated with the Company's downstream
activities.
DD&A expense increased to $16.1 million from $12.2 million reported in the first
nine months of 1995 due primarily to higher production volumes. The Company's
DD&A rate was $3.00 per BOE in both periods.
Interest expense for the nine months ended September 30, 1996, increased to
$12.8 million from $10.1 million reported for the comparative prior year period
primarily due to higher outstanding debt which was partially offset by a lower
overall average interest rate. Capitalized interest was $2.7 million and $2.3
million for the nine months ended September 30, 1996 and 1995, respectively.
The Company and certain of its officers and directors and a former director and
officer were named in two class action lawsuits filed in 1992 and 1993 seeking
an aggregate of approximately $90 million in compensatory damages and punitive
damages in an unspecified amount for alleged violations of the federal
securities laws and state common law arising out of certain alleged
misrepresentations and omissions in the Company's disclosure regarding its
onshore natural gas exploration activities. On March 6, 1996, the Company
announced that it had notified the court that a settlement in principle had been
reached in such cases. Under the terms of the settlement, the plaintiffs agreed
to dismiss all claims against the Company and its officers and directors in
exchange for a cash payment of approximately $6.25 million. Taking into account
prior costs incurred by the Company to defend these suits, this settlement
resulted in a charge to 1996 first quarter earnings of $4 million. By Order and
Final Judgment entered on September 30, 1996, the Court approved the Stipulation
of Settlement and the settlement amount was paid on November 1, 1996.
Approximately $4.1 million of such amount was paid by the Company's insurance
carrier and $2.2 million was paid by the Company.
Effective in 1992, Financial Accounting Standard 109 ("FAS 109") required
companies to record an asset or a liability, as appropriate for the net tax
position of each company as a result of differences between financial
reporting standards and tax reporting requirements. However, FAS 109 also
required companies with deferred tax assets to provide a valuation allowance for
the portion of the deferred tax asset that management concluded was more likely
than not to expire before the company would generate sufficient income to
realize such tax asset. The Company adopted FAS 109 in 1992 and at such time
recorded a net tax asset of approximately $20.8 million, but also recorded a
valuation reserve against the full amount of such asset to reflect management's
uncertainty, based on all information then available, with respect to the
realization of such asset.
Page 14 of 20
<PAGE>
At December 31, 1995, the Company had a net deferred tax asset of approximately
$18.3 million. While such amount was fully reserved, management was reassessing
the Company's ability to realize a portion of such asset in light of recent and
anticipated improvement in the Company's outlook for sustained profitability.
In the first quarter of 1996, the Company reduced its valuation allowance
resulting in the recognition of an $11 million credit to deferred income tax
expense. Management believes that it is more likely than not that it will
generate taxable income sufficient to realize the $11 million of unreserved tax
benefits associated with certain of the Company's net operating loss ("NOL")
carryforwards prior to their expiration. The reserve adjustment incorporates
management's assessment of the significant, cumulative progress made by the
Company over the last three years to reduce unit expenses, increase unit gross
margins and substantially increase its production and proved reserves through
its acquisition and exploitation activities. From 1992 to 1995, unit G&A
expenses declined 60%, unit gross profit increased 26% and production and proved
reserves increased 84% and 154%, respectively. Such reassessment is also
reinforced by 1996 events which include refinancing of long-term debt,
achievement of substantial expense reductions on the Illinois Basin properties
and results of drilling and other exploitation activities in the Company's other
core areas.
The remaining $7.3 million of the deferred tax asset was not recognized due to
limitations imposed by the IRS regarding the utilization of NOLs generated prior
to certain of the Company's subsidiaries being acquired and the uncertainty of
utilizing the Company's investment tax credit ("ITC") carryforwards. While the
Company's tax planning strategies address certain of these restrictions on the
application of subsidiary NOLs, management is currently uncertain as to the
extent such strategies will be successful and therefor concluded that a reserve
for these amounts was appropriate.
Estimates of future taxable income generated using future net cash flows
contained in reserve reports prepared by independent consulting firms in
accordance with regulations prescribed by the Securities and Exchange Commission
(the "SEC") also indicate that the unreserved portion of such deferred tax asset
will be realized. Such reserve data was utilized in calculating the
standardized measure of discounted future net cash flows (the "Standardized
Measure") presented in the Company's year-end financial statements. See Form 10-
K, Item 2, "Properties--Oil and Natural Gas Reserves." Despite the significant
turnaround achieved over the last three years and the current outlook for
profitability, due to the uncertainties in the oil and gas industry, including
but not limited to forecasting production, proved reserves, product prices,
production expenses and similar events beyond management's control, there can be
no assurance that the Company will generate any earnings or specific level of
continuing earnings.
The Company had carryforwards of approximately $164.1 million of regular tax
NOLs at December 31, 1995, which expire as follows: 1996 - $7.2 million; 1997 -
$3.6 million; 1998 - $5.1 million; 1999 - $7.1 million; 2000 - $7.9 million;
2001 - $4.4 million; 2002 - $11.8 million; 2003 - $9.4 million; 2004 - $0; 2005
- - $7.2 million; and thereafter through 2010 - $100.4 million.
For the nine months ended September 30, 1996, the Company recognized a net
deferred tax benefit before extraordinary item of $6.8 million. Such amount
consists of a $4.2 million deferred tax provision on the Company's income before
extraordinary item and the $11 million valuation allowance reduction previously
discussed. In addition, the Company reported a $3.4 million deferred tax
benefit reported as an extraordinary item. Such deferred tax benefit is
attributable to the $8.5 million pre-tax first quarter extraordinary loss from
the early redemption of the Company's 12% Notes.
Page 15 of 20
<PAGE>
CAPITAL RESOURCES, LIQUIDITY AND FINANCIAL CONDITION
On March 19, 1996, the Company sold $150 million of Senior Subordinated Notes
due 2006, Series A, bearing a coupon rate of 10.25% (the "Series A 10.25%
Notes"). Such notes were issued pursuant to a Rule 144A private placement at
approximately 99.38% to yield 10.35%. On August 8, 1996, the Company exchanged
a total of $149.5 million principal amount of the Series A 10.25% Notes for
10.25% Senior Subordinated Notes due 2006, Series B, (the "Series B 10.25%
Notes"). The Series B 10.25% Notes are substantially identical (including
principal amount, interest rate, maturity and redemption rights) to the Series A
10.25% Notes for which they were exchanged, except for certain transfer
restrictions relating to the Series A 10.25% Notes.
The Series A 10.25% Notes and the Series B 10.25% Notes (collectively, the
"10.25% Notes") are redeemable, at the option of the Company, on or after March
15, 2001 at 105.13%, at decreasing prices thereafter prior to March 15, 2004,
and thereafter at 100% plus, in each case, accrued interest to the date of
redemption. In addition, prior to March 15, 1999, up to $45 million in
principal amount of the 10.25% Notes are redeemable at the option of the
Company, in whole or in part, from time to time, at 110.25% of the principal
amount thereof, with the Net Proceeds of any Public Equity Offering (as both are
defined in the indenture under which the 10.25% Notes were issued ("the
"Indenture")).
The Indenture contains covenants including, but not limited to the following:
(i) limitations on incurrence of additional indebtedness; (ii) limitations on
certain investments; (iii) limitations on restricted payments; (iv) limitations
on disposition of assets; (v) limitations on dividends and other payment
restrictions affecting subsidiaries; (vi) limitations on transactions with
affiliates; (vii) limitations on liens; and (viii) restrictions on mergers,
consolidations and transfers of assets. In the event of a Change of Control and
a corresponding Rating Decline, as both are defined in the Indenture, the
Company will be required to make an offer to repurchase the 10.25% Notes at 101%
of the principal amount thereof, plus accrued and unpaid interest to the date of
the repurchase. The 10.25% Notes are unsecured general obligations of the
Company and are subordinated in right of payment to all existing and future
senior indebtedness of the Company and are guaranteed by all of the Company's
principal subsidiaries.
Proceeds from the sale of the 10.25% Notes, net of offering costs, were
approximately $144.6 million and were used to redeem the 12% Notes at 106% of
the $100 million principal amount outstanding and, together with amounts
borrowed under the Company's revolving credit facility (the "Revolving Credit
Facility"), to retire the Illinois Basin acquisition bridge indebtedness. Prior
to redemption, the 12% Notes had an average remaining life of three years and
scheduled maturities of $50 million in each of 1998 and 1999.
In April 1996, the Revolving Credit Facility and borrowing base thereunder were
increased to $125 million from $75 million. The Revolving Credit Facility, as
amended, matures on May 1, 1998, at which time the remaining outstanding balance
converts to a term loan which is repayable in twenty equal quarterly
installments commencing August 1, 1998. The Revolving Credit Facility bears
interest, at the option of the Company, at either LIBOR plus 1.75% or Base Rate
(as defined therein) plus .375%. Final maturity of the Revolving Credit
Facility occurs on May 1, 2003. The Revolving Credit Facility is guaranteed by
all of the Company's principal subsidiaries and is secured by the oil and gas
properties of the Company and its subsidiaries and the stock and personal
property of all subsidiary guarantors. At September 30, 1996, the Company had
$66.1 million in borrowings and a $1 million standby letter of credit
outstanding under the Revolving Credit Facility.
Page 16 of 20
<PAGE>
At September 30, 1996, the Company had a working capital deficit of
approximately $11 million compared to a deficit of $4.7 million at December 31,
1995. The Company has historically operated with a working capital deficit due
primarily to ongoing capital expenditures that have been financed through cash
flow and the Revolving Credit Facility.
Investing and Financing Activities
Net cash flows used in investing activities were $35.3 million and $15.9 million
for the nine months ended September 30, 1996 and 1995, respectively. Investing
activities include payments for acquisition, exploration and development costs
of $36.5 million and $16.9 million for these same periods, respectively. Also
included in investing activities are proceeds from the sale of certain
nonstrategic properties of $3.1 million and $1.8 million for the nine months
ended September 30, 1996 and 1995, respectively.
Net cash provided by financing activities amounted to $3.1 million and $5.1
million for the nine months ended September 30, 1996 and 1995, respectively.
Financing activities during 1996 include net proceeds of approximately $144.6
million from the Series A 10.25% Notes, approximately $107 million for the
repayment of the 12% Notes, including the 6% call premium and the net defeasance
costs, and approximately $42 million for the repayment of the Illinois Basin
acquisition bridge indebtedness. Included in both years are proceeds and
payments under the Revolving Credit Facility as a result of acquisition,
exploration and development activities.
Changing Oil and Natural Gas Prices
The Company is heavily dependent on crude oil prices which have historically
been volatile. Although the Company has routinely hedged a substantial portion
of its crude oil production and intends to continue this practice, future crude
oil price declines would have a negative impact on the Company's overall
results, and therefore its liquidity. Furthermore, low crude oil prices could
affect the Company's ability to raise capital on terms favorable to the Company.
For the fourth quarter of 1996, the Company has committed an average of
approximately 12,500 barrels of oil per day to fixed price arrangements at a
NYMEX index price of approximately $18 per barrel. Such amount represents
approximately 73% of 1996 third quarter average daily oil production. For 1997,
the Company has established hedges on (i) 12,000 barrels per day for the first
quarter at a NYMEX price of approximately $18.50 per barrel; (ii) 9,200 barrels
per day for April through December at a NYMEX price of approximately $18.65 per
barrel; and (iii) 2,000 barrels per day for January through December at a NYMEX
floor price of $19.00 per barrel and a NYMEX ceiling price of $24.00 per barrel.
All hedge prices are before applicable location and quality discounts. Such
arrangements partially mitigate the adverse impact of potential oil price
declines on the Company's operating results.
Page 17 of 20
<PAGE>
PART II. OTHER INFORMATION
Item 1 - Legal Proceedings
The information set forth in "Note 3 -- Litigation Settlement" to the Company's
financial statements included in Part I of this report and in "Part II, Item 1 -
Legal Proceedings" of the Company's Form 10-Q for the quarterly period ended
March 31, 1996, is incorporated herein by reference.
The Company and certain of its officers and directors and a former director and
officer were named as defendants in two class action lawsuits filed in the
United States District Court for the Southern District of Texas captioned Judith
Rubinstein, et al v. Collins, et al (C.A. No. 92-1297) and Gloria Moroson, v.
Collins, et al (C.A. No. H-93-2305). As previously reported, a Stipulation of
Settlement was filed with the Court in these cases. By Order and Final Judgment
entered on September 30, 1996, the Court approved the Stipulation of Settlement
and the settlement amount was paid on November 1, 1996.
As previously reported, Calumet Florida, Inc., a wholly-owned subsidiary of the
Company, is a party to a lawsuit in the United States District Court for the
Middle District of Florida styled Exxon Corporation v. E.W. Adams, et al., Case
Number 87-976-CIV-T-23-B. The Company has reached an agreement in principle
with all parties to settle this case. In consideration for full and final
settlement, and dismissal with prejudice of all issues in this case, the Company
has agreed to pay to the defendants the total sum of $100,000, and release
certain royalty amounts held in suspense and in the court registry during the
pendency of this case. Finalization of this settlement has been delayed due to
a dispute between the defendants over certain title issues. The defendants have
filed motions requesting the Court to rule on this dispute, but no hearing date
has been set. The Company does not believe that this dispute will adversely
affect the settlement reached between the Company and the defendants.
Item 2 - Material Modification of Rights of Registrant's Securities
None
Item 3 - Defaults on Senior Securities
None
Item 4 - Submission of Matters to a Vote of Security Holders
None
Item 5 - Other Information
None
Item 6 -
A. Exhibits
Page 18 of 20
<PAGE>
11(a) Computation of per share earnings for the three months ended September
30, 1996 and 1995
11(b) Computation of per share earnings for the nine months ended September
30, 1996 and 1995
27. Financial Data Schedule
B. Report on Form 8-K
None
Page 19 of 20
<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 and thereunto duly authorized.
PLAINS RESOURCES INC.
Date: November 12, 1996 By: /s/ Cynthia A. Feeback
-------------------------------------
Cynthia A. Feeback, Controller and
Principal Accounting Officer
(Principal Accounting Officer)
Page 20 of 20
<PAGE>
EXHIBIT 11a. - Computation of Per Share Earnings
(in thousands except per share data) (unaudited)
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
THREE MONTHS ENDED SEPTEMBER 30,
-----------------------------------------------
1996 1995
-----------------------------------------------
Common and Common and
Common Common
Equivalent Full Equivalent Full
Shares Dilution Shares Dilution
----------- ---------- ----------- ---------
<S> <C> <C> <C> <C>
Weighted average common shares outstanding 16,342 16,342 15,286 15,286
Incremental shares assumed to be issued 1,479 1,521 888 888
------- ------- ------- -------
Total shares outstanding for calculation 17,821 17,863 16,174 16,174
======= ======= ======= =======
Net income before extraordinary item as reported $ 3,486 $ 3,486 $ 483 $ 483
Deduct dividends on Cumulative Convertible Preferred Stock -- -- (11) (11)
------- ------- ------- -------
Net income available to common shareholders before $ 3,486 $ 3,486 $ 472 $ 472
extraordinary item
Extraordinary item 1,515 1,515 -- --
------- ------- ------- -------
Net income for calculation $ 5,001 $ 5,001 $ 472 $ 472
======= ======= ======= =======
Net income per share:
Before extraordinary item $ .20 $ .20 $ .03 $ .03
Extraordinary item .08 .08 -- --
------- ------- ------- -------
$ .28 $ .28 $ .03 $ .03
======= ======= ======= =======
</TABLE>
<PAGE>
EXHIBIT 11b. - Computation of Per Share Earnings
(in thousands except per share data) (unaudited)
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
NINE MONTHS ENDED SEPTEMBER 30,
----------------------------------------------
1996 1995
-------------------- ---------------------
Common and Common and
Common Common
Equivalent Full Equivalent Full
Shares Dilution Shares Dilution
---------- --------- ---------- --------
<S> <C> <C> <C> <C>
Weighted average common shares outstanding 16,253 16,253 13,333 13,333
Incremental shares assumed to be issued 1,325 1,610 2,618 2,618
------- ------- ------- -------
Total shares outstanding for calculation 17,578 17,863 15,951 15,951
======= ======= ======= =======
Net income before extraordinary item as reported $17,316 $17,316 $ 1,716 $ 1,716
Deduct dividends on Cumulative Convertible Preferred Stock -- -- (42) (42)
------- ------- ------- -------
Net income available to common shareholders before extraordinary item $17,316 $17,316 $ 1,674 $ 1,674
Extraordinary item (5,104) (5,104) -- --
------- ------- ------- -------
Net income for calculation $12,212 $12,212 $ 1,674 $ 1,674
======= ======= ======= =======
Net income (loss) per share:
Before extraordinary item $ .98 $ .97 $ .10 $ .10
Extraordinary item (.29) (.29) - -
------- ------- ------- -------
$ .69 $ .68 $ .10 $ .10
======= ======= ======= =======
</TABLE>
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PLAINS
RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEET AS OF
SEPTEMBER 30, 1996, AND CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS FOR THE
NINE MONTHS ENDED SEPTEMBER 30, 1996 AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> SEP-30-1996
<CASH> 625
<SECURITIES> 0
<RECEIVABLES> 79,336
<ALLOWANCES> 0
<INVENTORY> 6,977
<CURRENT-ASSETS> 86,938
<PP&E> 454,847
<DEPRECIATION> 152,605
<TOTAL-ASSETS> 409,707
<CURRENT-LIABILITIES> 97,892
<BONDS> 218,785
0
0
<COMMON> 1,643
<OTHER-SE> 89,217
<TOTAL-LIABILITY-AND-EQUITY> 409,707
<SALES> 448,468
<TOTAL-REVENUES> 448,688
<CGS> 399,359
<TOTAL-COSTS> 415,412
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 12,806
<INCOME-PRETAX> 10,529
<INCOME-TAX> (6,787)
<INCOME-CONTINUING> 17,316
<DISCONTINUED> 0
<EXTRAORDINARY> (5,104)
<CHANGES> 0
<NET-INCOME> 12,212
<EPS-PRIMARY> .69
<EPS-DILUTED> .68
</TABLE>
