<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 JUNE 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)
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
---- ----
16,278,170 shares of common stock $.10 par value, issued and outstanding at
July 31, 1996.
Page 1
<PAGE>
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>
PART I. FINANCIAL INFORMATION
<TABLE>
<CAPTION>
PAGE
<S> <C>
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:
Condensed Consolidated Balance Sheets:
June 30, 1996 and December 31, 1995...........................3
Condensed Consolidated Statements of Operations:
For the three and six months ended June 30, 1996 and 1995.....4
Condensed Consolidated Statements of Cash Flows:
For the six months ended June 30, 1996 and 1995...............5
Notes to Condensed Consolidated Financial Statements..........6
</TABLE>
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
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (in thousands, except share data)
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------------------
JUNE 30, DECEMBER 31,
1996 1995
----------- ------------
(unaudited)
ASSETS
CURRENT ASSETS
<S> <C> <C>
Cash and cash equivalents $ 5,605 $ 6,129
Accounts receivable and other 71,049 52,383
Inventory 4,385 5,120
--------- ---------
Total current assets 81,039 63,632
--------- ---------
PROPERTY AND EQUIPMENT
Oil and natural gas properties - full cost method:
Subject to amortization 346,897 328,712
Not subject to amortization 50,301 48,795
Downstream assets, primarily crude oil terminal and storage facility 34,634 32,788
Other property and equipment 7,527 7,789
--------- ---------
439,359 418,084
Less allowance for depreciation, depletion and amortization (147,285) (137,546)
--------- ---------
292,074 280,538
--------- ---------
DEFERRED INCOME TAXES, NET 11,000 --
OTHER ASSETS 9,869 7,876
--------- ---------
$ 393,982 $ 352,046
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and other current liabilities $ 77,259 $ 56,573
Interest payable 5,253 3,977
Royalties payable and drilling advances 6,431 6,364
Notes payable and other current obligations 521 1,467
--------- ---------
Total current liabilities 89,464 68,381
BANK DEBT 65,000 98,000
SUBORDINATED DEBT 149,093 100,000
OTHER LONG-TERM DEBT 4,089 7,089
OTHER LONG-TERM LIABILITIES 1,496 1,547
--------- ---------
309,142 275,017
--------- ---------
STOCKHOLDERS' EQUITY
Common stock, $.10 par value, 50,000,000 shares authorized; 1,628 1,618
issued and outstanding 16,276,490 at June 30, 1996,
and 16,178,670 shares at December 31, 1995
Additional paid-in capital 118,680 118,090
Accumulated deficit (35,468) (42,679)
--------- ---------
84,840 77,029
--------- ---------
$ 393,982 $ 352,046
========= =========
</TABLE>
See notes to condensed consolidated financial statements.
Page 3
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited) (in thousands,
except per share data)
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------------------------------
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------- ---------------------
1996 1995 1996 1995
-------- ------- --------- ---------
<S> <C> <C> <C> <C>
REVENUE
Oil and natural gas sales $ 25,115 $15,789 $ 45,772 $ 30,478
Marketing, transportation and storage 130,760 79,392 233,550 158,278
Interest and other income 55 75 121 147
-------- ------- --------- ---------
155,930 95,256 279,443 188,903
-------- ------- --------- ---------
EXPENSES
Production expenses 9,319 7,148 18,631 13,907
Purchases, transportation and storage 128,258 77,796 229,099 155,184
General and administrative 1,984 1,876 4,042 3,774
Depreciation, depletion and amortization 5,532 4,127 10,421 8,125
Interest expense 4,335 3,395 8,532 6,680
Litigation settlement -- -- 4,000 --
-------- ------- --------- ---------
149,428 94,342 274,725 187,670
-------- ------- --------- ---------
Income before income taxes and extraordinary item 6,502 914 4,718 1,233
Income tax expense (benefit) 1,888 -- (9,112) --
-------- ------- --------- ---------
INCOME BEFORE EXTRAORDINARY ITEM 4,614 914 13,830 1,233
EXTRAORDINARY ITEM:
(Loss) on early extinguishment of debt, net of tax benefit 1,888 -- (6,619) --
-------- ------- --------- ---------
NET INCOME $ 6,502 $ 914 $ 7,211 $ 1,233
======== ======= ========= =========
Net income (loss) per common and common equivalent share:
Before extraordinary item $.26 $.06 $.80 $.08
Extraordinary item .11 -- (.38) --
-------- ------- --------- ---------
$.37 $.06 $.42 $.08
======== ======= ========= =========
Weighted average number of common and common equivalent shares 17,573 16,002 17,335 15,737
======== ======= ========= =========
</TABLE>
See notes to condensed consolidated financial statements.
Page 4
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited) (in thousands)
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------------------------
SIX MONTHS ENDED
JUNE 30,
----------------------------
1996 1995
--------- ---------
<S> <C> <C>
NET CASH PROVIDED BY OPERATING ACTIVITIES $ 18,287 $ 6,718
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from the sale of oil and natural gas properties 3,066 1,765
Payment for acquisition, exploration and development costs (22,326) (8,343)
Payment for additions to other property and assets (1,188) (695)
--------- ---------
Net cash used in investing activities (20,448) (7,273)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt 202,223 23,750
Principal payments of long-term debt (189,900) (18,850)
Costs incurred to redeem long-term debt (6,468) -
Payments of other long-term debt (3,946) (1,505)
Other (272) 224
--------- ---------
Net cash provided by financing activities 1,637 3,619
--------- ---------
Net increase (decrease) in cash and cash equivalents (524) 3,064
Cash and cash equivalents, beginning of period 6,129 1,291
--------- ---------
Cash and cash equivalents, end of period $ 5,605 $ 4,355
========= =========
</TABLE>
See notes to condensed consolidated financial statements.
Page 5
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
JUNE 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 June 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%. The Series A 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 Series A
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 (as defined therein) of any Public Equity Offering (as defined
therein).
The indenture under which the Series A 10.25% Notes were issued (the
"Indenture") contains covenants including, but not limited to, covenants with
respect 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 Series A 10.25% Notes at 101% of the principal amount thereof,
plus accrued and unpaid interest to the date of the repurchase. The Series A
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 Series A 10.25% Notes, net of offering costs, were
approximately $144.9 million and were used to redeem the Company's 12% Senior
Subordinated Notes (the "12% Notes") at 106% of the $100 million principal
amount outstanding and to retire bridge bank indebtedness which was
Page 6
<PAGE>
incurred in December 1995 in connection with the acquisition of certain oil
properties. 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.
On June 26, 1996, the Company commenced an offer to exchange 10.25% Senior
Subordinated Notes due 2006, Series B, (the "Series B 10.25% Notes") for all of
the outstanding Series A 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 may be exchanged,
except for certain transfer restrictions and registration rights relating to the
Series A 10.25% Notes and except for certain interest provisions relating to
such rights. The exchange offer expired on August 8, 1996, with a total
principal amount of $149.5 million of the Series A 10.25% Notes being exchanged.
On March 19, 1996, the Company called for the redemption of the 12% Notes and
deposited $112.6 million with the trustee of the 12% Notes to cover the
principal amount called, the call premium of $6 million and $6.6 million for
accrued interest through the redemption date. The 12% Notes were redeemed on
April 18, 1996, and the Company has recognized an extraordinary loss of $6.6
million, net of deferred tax benefit of $1.9 million, through June 30, 1996 (See
Note 4).
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 June 30, 1996,
the Company had $65 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. Approximately $4.1
million of such amount is expected to be paid by the Company's insurance
carrier, leaving approximately $2.1 million to be contributed by the Company.
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. The settlement is subject to the approval of the court. A hearing has
been set for September 25, 1996, for the court to determine whether the
settlement agreement should be approved. If the settlement is not consummated
and if the Company ultimately were required to pay a substantial portion of the
$90 million in compensatory damages sought by the plaintiffs, it would have a
material adverse effect on the Company.
Page 7
<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 June 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 four 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.
During the second quarter of 1996, the Company recognized a deferred tax
provision of $1.9 million and an offsetting $1.9 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
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Three month periods ended June 30, 1996 and 1995
For the quarter ended June 30, 1996, the Company reported net income before
extraordinary items of $4.6 million, or $.26 per share, on total revenue of
$155.9 million. This compares with net income of $914,000, or $.06 per share,
on total revenue of $95.3 million for the second quarter of 1995. Net income
after extraordinary items was $6.5 million, or $.37 per share. Cash flow from
operations (net income plus noncash expenses) more than doubled, increasing 139%
to $12.0 million as compared to $5.0 million in the second quarter of 1995.
Earnings before interest, taxes, depreciation, depletion and amortization
("EBITDA") increased 94% to $16.4 million as compared to $8.4 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:
<TABLE>
<CAPTION>
THREE MONTHS ENDED
JUNE 30,
----------------------------------
1996 1995
---------------- ----------------
(in thousands, except per unit data)
(unaudited)
<S> <C> <C>
AVERAGE DAILY PRODUCTION VOLUMES
BARRELS OF OIL EQUIVALENT ("BOE")
LA Basin (91% oil)................... 9.2 8.5
S. Florida (100% oil)................ 5.2 3.5
Illinois Basin (100% oil)............ 3.4 --
Sold properties...................... -- .9
------ ------
Total (95% oil)...................... 17.8 12.9
====== ======
AVERAGE SALES PRICE
Per barrel of oil.................... $16.01 $14.31
====== ======
Per mcf of natural gas............... $ .74 $ 1.02
====== ======
UNIT ECONOMICS
Average sales price per BOE.......... $15.47 $13.44
Production expenses per BOE.......... 5.74 6.09
------ ------
Gross margin per BOE................. 9.73 7.35
Upstream G&A expenses per BOE........ .79 1.10
------ ------
Gross profit per BOE................. $ 8.94 $ 6.25
====== ======
</TABLE>
Oil and natural gas production for the second quarter of 1996 increased 38% to
1.62 million BOE, as compared to the 1.18 million BOE produced in last year's
comparative quarter. The Company's unit gross margin increased to $9.73 per
BOE, a 32% improvement over the $7.35 per BOE recorded in last year's second
quarter. Unit gross profit, which deducts all pre-interest cash costs
attributable to the upstream segment, was $8.94 per BOE, up 43% over 1995's
second quarter amount of $6.25 per BOE.
Page 9
<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 half of 1996, average net daily production from the
Company's LA Basin properties increased to approximately 9,200 BOE per day, up
700 BOE per day, or 8% over last year's comparative quarter. Net production
from the Company's South Florida Sunniland Trend properties increased
approximately 50% to average 5,200 barrels of oil per day in the second quarter
of 1996 as compared to 3,500 barrels per day in last year's second quarter. The
current quarter average incorporates the impact of production from the Company's
recent 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 second quarter averaged around 3,100 barrels of oil and 300
barrels of water per day. 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 in 1995 and 1996 and the
acquisition of the Company's Illinois Basin properties in December 1995.
Production attributable to properties sold totaled 87,000 BOE or an average of
956 BOE per day during the 1995 second quarter. Net production from the
Illinois Basin properties totaled 314,000 barrels of oil or an average of 3,400
barrels of oil per day during the second 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 59% to $25.1 million for the second
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 15% to $15.47 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 unhedged
production of increased crude oil prices. During the current year quarter, the
NYMEX benchmark price averaged $21.57 per barrel, up 12% as compared to an
average of $19.32 per barrel in the correlative period of 1995. This price
increase had an approximate $1.4 million impact on the Company's net income and
cash flow in the 1996 second quarter. Approximately 58% of the Company's oil
production was hedged during the 1996 second quarter. 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 $2.12 and $.42 in
the second quarter of 1996 and 1995, respectively.
The Company's downstream segment reported a gross margin (marketing,
transportation and storage revenues less purchases, transportation and storage
expenses) of $2.5 million for the second quarter of 1996, reflecting an
approximate 57% increase over the $1.6 million reported for the 1995 quarter.
Gross revenues were $130.8 million and $79.4 million for the respective periods.
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 second quarter of 1996. Approximately $300,000 of the current
year gross margin is attributable to the strong market demand for crude oil in
the second quarter of 1996. Total average daily crude oil volumes marketed and
terminalled during the 1996 second quarter were 59,000 barrels and 51,000
barrels, respectively. Such amounts represent respective increases of 37% and
31% as compared with average daily volumes of 43,000 barrels and 39,000 barrels
in last year's second quarter. As a result of the relatively fixed portion of
this segment's overhead and operating infrastructure, gross profit (gross margin
less downstream general and administrative ("G&A") expenses) increased 75% to
$1.8 million versus $1.0 million in last year's second quarter.
Page 10
<PAGE>
Aggregate unit production expenses declined 6% to $5.74 per BOE versus $6.09 per
BOE in the second quarter of 1995. Unit production expenses were $6.56 per BOE
in the first quarter of 1996. The reduction in average unit production expenses
is attributable to increased production from fields with a high component of
fixed production costs which do not increase with incremental production and
reimbursements received in the second quarter of 1996 for electricity
overcharges in the previous year. Excluding the electricity reimbursement, unit
production expenses were $5.88 per BOE, or 3% below 1995's second quarter
level. Total production expenses increased to $9.3 million from $7.1 million
for the second quarter of 1995 primarily due to the acquisition of the Illinois
Basin properties.
Unit production expenses for the LA Basin properties were $5.90 per BOE for the
second quarter of 1996, or 6% lower than last year's comparative quarter
partially due to the electricity reimbursement previously discussed. Excluding
this adjustment, unit production expenses were $6.18 per BOE, a 2% reduction
compared to last year. Unit production expenses for the South Florida Sunniland
Trend properties averaged $3.63 per BOE, approximately 32% lower than the 1995
second quarter average of $5.30 per BOE. This reduction is primarily
attributable to increased production from fields with a high component of fixed
production costs which do not increase with incremental production. The
decrease in unit production expenses in these areas was offset to some extent by
the addition of the higher cost Illinois Basin production. Unit production
expenses for these properties, which averaged $12.00 per barrel in the fourth
quarter of 1995, averaged approximately $8.50 per barrel during the first and
second quarters of 1996. The significant reduction in production expenses for
the Illinois Basin properties is a result of operational modifications
implemented in late 1995 and throughout the first half of 1996.
The Company extended its three year trend of reducing unit G&A expenses as unit
upstream G&A expenses decreased 28% to $.79 per BOE as compared to $1.10 per BOE
in last year's comparative quarter. Total G&A expenses, including downstream
activities, were $2.0 million for the three months ended June 30, 1996, compared
to $1.9 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 $5.5
million from $4.1 million reported in the second 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 June 30, 1996, increased to
$4.3 million from $3.4 million for the comparative prior year quarter primarily
due to higher outstanding debt levels which were partially offset by a lower
overall average interest rate. Capitalized interest was $.9 million and $.8
million for the three months ended June 30, 1996 and 1995, respectively.
During the second quarter, the Company recognized a deferred tax provision of
$1.9 million and an offsetting $1.9 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 (the "12% Notes").
Six month periods ended June 30, 1996 and 1995
For the six months ended June 30, 1996, the Company reported net income before
nonrecurring items of $6.8 million, or $.39 per share, on total revenue of
$279.4 million. This compares with net income of $1.2 million, or $.08 per
share, on total revenue of $188.9 million for the first half of 1995. Cash flow
from operations (net income plus noncash expenses) was $19.1 million, more than
double the $9.4 million reported in the 1995 period. EBITDA increased 73% to
$27.7 million as compared to $16.0 million in the first six months of 1995.
Such amounts are also presented before the effects of the nonrecurring items.
Net cash provided by operating activities, as reported in the consolidated
statements of cash flows,
Page 11
<PAGE>
increased to $18.3 million for the six months ended June 30, 1996, as compared
to $6.7 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 a $6.6 million extraordinary loss associated with the
early redemption of the 12% Notes, 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 the Company's
deferred tax asset. Such items resulted in an aggregate increase to net income
of $400,000 or $.02 per share. After giving effect to such nonrecurring items,
the Company reported net income for the first six months of 1996 of $7.2
million, or $.42 per share. Before extraordinary items, net income was $13.8
million or $.80 per share.
The following table sets forth certain operating information of the Company for
the periods presented:
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30,
----------------------------------
1996 1995
---------------- ----------------
(in thousands, except per unit data)
(unaudited)
<S> <C> <C>
AVERAGE DAILY PRODUCTION VOLUMES
BARRELS OF OIL EQUIVALENT
LA Basin (91% oil).............. 9.0 8.3
S. Florida (100% oil)........... 4.2 3.5
Illinois Basin (100% oil)....... 3.4 --
Sold properties................. .1 1.0
------ ------
Total (95% oil)................. 16.7 12.8
====== ======
AVERAGE SALES PRICE
Per barrel of oil............... $15.65 $13.97
====== ======
Per mcf of natural gas.......... $ .77 $ 1.05
====== ======
UNIT ECONOMICS
Average sales price per BOE..... $15.04 $13.14
Production expenses per BOE..... 6.12 5.99
------ ------
Gross margin per BOE............ 8.92 7.15
Upstream G&A expenses per BOE... .85 1.10
------ ------
Gross profit per BOE............ $ 8.07 $ 6.05
====== ======
</TABLE>
Oil and natural gas production for the first six months of 1996 increased 31% to
3.0 million BOE versus the 2.3 million BOE produced in the 1995 comparative
period. The Company's unit gross margin increased to $8.92 per BOE, a 25%
improvement over the $7.15 per BOE recorded in last year's first half. Unit
gross profit, which deducts all pre-interest cash costs attributable to the
upstream segment, was $8.07 per BOE, up 33% over 1995's first half average of
$6.05 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 half of 1996, average net daily production from the
Company's LA Basin properties for the first half of 1996 increased to
approximately 9,000 BOE per day, up 700 BOE per day, or 8% over last year's
comparative period. Net production
Page 12
<PAGE>
from the Company's South Florida Sunniland Trend properties increased
approximately 20% to average 4,200 barrels of oil per day in the first half 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 recent 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 second quarter averaged around 3,100
barrels of oil and 300 barrels of water per day. The Company owns a 100%
working interest and an 84% net revenue interest in this well.
The period to period comparisons of production volumes and unit margins were
affected by sales of nonstrategic properties in 1995 and 1996 and the
acquisition of the Company's Illinois Basin properties in December 1995.
Production attributable to properties sold totaled 179,000 BOE or an average of
983 BOE per day during the first half of 1995. Net production from the Illinois
Basin properties totaled 632,000 barrels of oil or an average of 3,400 barrels
of oil per day during the first six months of 1996.
Oil and natural gas revenues increased 50% to $45.8 million for the first six
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 14% to $15.04 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 unhedged
production of increased crude oil prices. During the current year, the NYMEX
benchmark price averaged $20.56 per barrel, up 9% as compared to an average of
$18.84 in the correlative period of 1995. This price increase had an
approximate $1.6 million impact on the Company's net income and cash flow for
the six months ended June 30, 1996. Approximately 66% of the Company's oil
production was hedged during the first half of 1996. 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 average price per BOE by $1.82 and $.43 in the first
half of 1996 and 1995, respectively.
The Company's downstream segment reported a gross margin (marketing,
transportation and storage revenues less purchases, transportation and storage
expenses) of $4.5 million for the first half of 1996, reflecting an approximate
44% increase over the $3.1 million reported for the 1995 period. Gross revenues
were $233.6 million and $158.3 million for the respective periods. Such results
are directly attributable to continued expansion of the downstream segment's
base level activities and strong market demand for crude oil during the second
quarter of 1996. Approximately $300,000 of the current year gross margin is
attributable to the strong market demand for crude oil in the second quarter of
1996. Total average daily crude oil volumes marketed and terminalled during the
1996 first half were 56,000 barrels and 55,000 barrels, respectively. Such
amounts represent respective increases of 24% and 41% as compared with average
daily volumes of 45,000 barrels and 39,000 barrels in last year's first half.
As a result of the relatively fixed portion of this segment's overhead and
operating infrastructure, gross profit (gross margin less downstream G&A
expenses) increased 59%, totaling $3.0 million versus $1.9 million in first six
months of last year.
Primarily as a result of the higher cost Illinois Basin production, unit
production expenses in the first half of 1996 increased approximately 2% to
$6.12 per BOE. Unit production expenses for the Illinois Basin properties,
which averaged $12.00 per barrel in the fourth quarter of 1995, averaged
approximately $8.50 per barrel for the six month period. The significant
reduction in production expenses for the Illinois Basin
Page 13
<PAGE>
properties is a result of operational modifications implemented in late 1995 and
throughout the first half of 1996.
The increase in unit production expenses attributable to the Illinois Basin
properties was partially offset by decreases in unit production expenses in the
Company's other core areas. Unit production expenses for the LA Basin
properties were $6.22 per BOE for the first six months of 1996, or 3% lower than
last year's comparative period primarily due to expense reimbursements received
in the second quarter of 1996 for electricity overcharges in the previous year.
Unit production expenses for the South Florida Sunniland Trend properties
averaged $4.02 per BOE, approximately 21% lower than the 1995 first half average
of $5.06 per BOE. This reduction is primarily attributable to increased
production from fields with a high component of fixed production costs which do
not increase with incremental production. Total production expenses increased to
$18.6 million from $13.9 million for the first half 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 unit
upstream G&A expenses decreased 23% to $.85 per BOE as compared to $1.10 per BOE
in last year's first half. Total G&A expenses, including downstream activities,
were $4.0 million for the six months ended June 30, 1996, compared to $3.8
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 $10.4 million from $8.1 million reported in the first
half 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 six months
ended June 30, 1996, increased to $8.5 million from $6.7 million reported for
the comparative prior year period primarily due to higher outstanding debt
levels which were partially offset by a lower overall average interest rate.
Capitalized interest was $1.8 million and $1.5 million for the six months ended
June 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. Approximately $4.1
million of such amount is expected to be paid by the Company's insurance
carrier, leaving approximately $2.1 million to be contributed by the Company.
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. The settlement is subject to the approval of the Court. A hearing has
been set for September 25, 1996, for the Court to determine whether the
settlement agreement should be approved.
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 temporary 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
<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 first quarter 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 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
assets 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.
During the second quarter, the Company recognized a deferred tax provision of
$1.9 million and an offsetting $1.9 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 12% Notes.
In April 1996, the Company redeemed the 12% Notes and in connection therewith,
the Company has recognized an extraordinary loss of $6.6 million, net of
deferred tax benefit, through June 30, 1996.
Page 15
<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%. The Series A 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 Series A
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 (as defined therein) of any Public Equity Offering (as defined
therein).
The indenture under which the Series A 10.25% Notes were issued (the
"Indenture") contains covenants including, but not limited to, covenants with
respect 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 Series A 10.25% Notes at 101% of the principal amount thereof,
plus accrued and unpaid interest to the date of the repurchase. The Series A
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 Series A 10.25% Notes, net of offering costs, were
approximately $144.9 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.
On June 26, 1996, the Company commenced an offer to exchange 10.25% Senior
Subordinated Notes due 2006, Series B, (the "Series B 10.25% Notes") for all of
the outstanding Series A 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 may be exchanged,
except for certain transfer restrictions and registration rights relating to the
Series A 10.25% Notes and except for certain interest provisions relating to
such rights. The exchange offer expired on August 8, 1996, with a total
principal amount of $149.5 million of the Series A 10.25% Notes being exchanged.
In April 1996, 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 June 30, 1996, the Company had $65
million in borrowings and a $1 million standby letter of credit outstanding
under the Revolving Credit Facility.
Page 16
<PAGE>
At June 30, 1996, the Company had a working capital deficit of approximately
$8.4 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 $20.4 million and $7.3 million
for the six months ended June 30, 1996 and 1995, respectively. Investing
activities include payments for acquisition, exploration and development costs
of $22.3 million and $8.3 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 six months
ended June 30, 1996 and 1995, respectively.
Net cash provided by financing activities amounted to $1.6 million and $3.6
million for the six months ended June 30, 1996 and 1995, respectively.
Financing activities during 1996 include net proceeds of approximately $144.9
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 second half of 1996, the Company has committed an average of
approximately 12,500 barrels of oil per day, or approximately 70% of 1996 second
quarter average daily production, to fixed price arrangements at a NYMEX index
price (before location and quality discounts) of approximately $18 per barrel.
The Company has also established hedges on approximately 11,000 barrels per day
for the first quarter of 1997 at approximately $18.50 per barrel, and an average
of approximately 5,000 barrels per day at approximately $18.00 per barrel
through the remainder of 1997. Such arrangements partially mitigate the adverse
impact of potential oil price declines on the Company's operating results.
Page 17
<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 has been filed with the Court in these cases. A hearing has been set
for September 25, 1996, for the court to determine whether the settlement
agreement set forth in the Stipulation of Settlement should be approved.
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. The parties have agreed to use their best efforts to
draft and execute by August 24, 1996, the definitive settlement documents
required to finalize this settlement.
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
The 1996 Annual Meeting of Stockholders (the "Meeting") of the Company was held
on May 23, 1996. At the Meeting, holders of common stock, $.10 par value, of the
Company ("Common Stock"), elected eight members of the Company's Board of
Directors and approved the Company's 1996 Stock Incentive Plan. No other
matters were voted on at the Meeting.
Out of the 16,183,320 shares of Common Stock entitled to vote at the Meeting,
there were 13,670,523 shares of Common Stock represented at the Meeting either
by proxies solicited in accordance with Schedule 14A or by security holders
voting in person.
The tabulation of votes for each director nominee is as follows:
<TABLE>
<CAPTION>
NOMINEES FOR ELECTION TO THE
COMPANY'S BOARD OF DIRECTORS Votes "For" Withheld
----------- --------
<S> <C> <C>
Greg L. Armstrong 13,646,882 23,641
Robert A. Bezuch 13,646,847 23,676
Tom H. Delimitros 13,646,847 23,676
William H. Hitchcock 13,646,987 23,536
Dan M. Krausse 13,646,484 24,039
John H. Lollar 13,646,832 23,691
Robert V. Sinnott 13,647,047 23,476
J. Taft Symonds 13,647,087 23,436
</TABLE>
Page 18
<PAGE>
With respect to the 1996 Stock Incentive Plan, 7,608,658 votes were cast in
favor of the plan, 2,493,491 votes were cast against the plan, 29,547 shares
abstained from voting and there were 3,538,827 broker non-votes.
Item 5 - Other Information
None
Item 6 -
A. Exhibits
11(a) Computation of per share earnings for the three months ended June 30,
1996 and 1995
11(b) Computation of per share earnings for the six months ended June 30,
1996 and 1995
27. Financial Data Schedule
B. Report on Form 8-K
None
Page 19
<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: August 9, 1996 By: /s/ Cynthia A. Feeback
-------------------------
Cynthia A. Feeback, Controller and
Principal Accounting Officer
(Principal Accounting Officer)
Page 20
<PAGE>
EXHIBIT 11a. - Computation of Per Share Earnings (in thousands except per share
data) (unaudited)
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
THREE MONTHS ENDED JUNE 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 16,233 16,233 13,078 13,078
Incremental shares assumed to be issued 1,340 1,469 2,924 2,924
------- ------- ------- -------
Total shares outstanding for calculation 17,573 17,702 16,002 16,002
======= ======= ======= =======
Net income before extraordinary item as reported $ 4,614 $ 4,614 $ 914 $ 914
Deduct dividends on Cumulative Convertible Preferred Stock -- -- (16) (16)
------- ------- ------- -------
Net income available to common shareholders before $ 4,614 $ 4,614 $ 898 $ 898
extraordinary item
Extraordinary item 1,888 1,888 -- --
------- ------- ------- -------
Net income for calculation $ 6,502 $ 6,502 $ 898 $ 898
======= ======= ======= =======
Net income per share:
Before extraordinary item $ .26 $ .26 $ .06 $ .06
Extraordinary item .11 .11 -- --
------- ------- ------- -------
$ .37 $ .37 $ .06 $ .06
======= ======= ======= =======
</TABLE>
<PAGE>
EXHIBIT 11b. - Computation of Per Share Earnings (in thousands except per share
data) (unaudited)
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 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 16,208 16,208 12,340 12,340
Incremental shares assumed to be issued 1,127 1,494 3,397 3,635
------- ------- ------- -------
Total shares outstanding for calculation 17,335 17,702 15,737 15,975
======= ======= ======= =======
Net income before extraordinary item as reported $13,830 $13,830 $ 1,233 $ 1,233
Deduct dividends on Cumulative Convertible Preferred Stock -- -- (31) (31)
------- ------- ------- -------
Net income available to common shareholders before $13,830 $13,830 $ 1,202 $ 1,202
extraordinary item
Extraordinary item (6,619) (6,619) -- --
------- ------- ------- -------
Net income for calculation $ 7,211 $ 7,211 $ 1,202 $ 1,202
======= ======= ======= =======
Net income (loss) per share:
Before extraordinary item $ .80 $ .78 $ .08 $ .08
Extraordinary item (.38) (.37) -- --
------- ------- ------- -------
$ .42 $ .41 $ .08 $ .08
======= ======= ======= =======
</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 June
30, 1996, and Condensed Consolidated Statement of Operations for the six months
ended June 30, 1996 and is qualified in its entirety by reference to such
financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> JUN-30-1996
<CASH> 5,605
<SECURITIES> 0
<RECEIVABLES> 71,049
<ALLOWANCES> 0
<INVENTORY> 4,385
<CURRENT-ASSETS> 81,039
<PP&E> 439,359
<DEPRECIATION> 147,285
<TOTAL-ASSETS> 393,982
<CURRENT-LIABILITIES> 89,464
<BONDS> 218,182
0
0
<COMMON> 1,628
<OTHER-SE> 83,212
<TOTAL-LIABILITY-AND-EQUITY> 393,982
<SALES> 279,322
<TOTAL-REVENUES> 279,443
<CGS> 247,730
<TOTAL-COSTS> 258,151
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 8,532
<INCOME-PRETAX> 4,718
<INCOME-TAX> (9,112)
<INCOME-CONTINUING> 13,830
<DISCONTINUED> 0
<EXTRAORDINARY> (6,619)
<CHANGES> 0
<NET-INCOME> 7,211
<EPS-PRIMARY> .42
<EPS-DILUTED> .41
</TABLE>
