<PAGE>
- --------------------------------------------------------------------------------
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
___________________________
FORM 10-K/A
AMENDMENT NO. 1
AMENDMENT TO ANNUAL REPORT PURSUANT TO
SECTION 13 OR 15 (D)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1998
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 Number)
500 DALLAS
HOUSTON, TEXAS 77002
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (713) 654-1414
Securities registered pursuant to Section 12(b) of the Act:
Title of each class: Name of each exchange on which registered:
----------------------- --------------------------------------------
Common Stock, par value American Stock Exchange
$.10 per share
Securities registered pursuant to Section 12(g) of the Act: None
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 the filing
requirements for the past 90 days.
Yes x No
---- ----
The aggregate value of the Common Stock held by non-affiliates of the registrant
(treating all executive officers and directors of the registrant, for this
purpose, as if they may be affiliates of the registrant) was approximately
$234,602,780 on March 26, 1999 (based on $14.25 per share, the last sale price
of the Common Stock as reported on the American Stock Exchange Composite Tape on
such date).
16,891,617 shares of the registrant's Common Stock were outstanding
as of March 26, 1999.
DOCUMENTS INCORPORATED BY REFERENCE. The information required in Part III of
this Annual Report on Form 10-K is incorporated by reference to the Registrant's
definitive proxy statement to be filed pursuant to Regulation 14A for the
Registrant's Annual Meeting of Stockholders.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
- --------------------------------------------------------------------------------
<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: September 21, 1999 By: /s/ Cynthia A. Feeback
--------------------------
Cynthia A. Feeback, Controller;
Vice President - Accounting and
Assistant Treasurer
(Principal Accounting Officer)
2
<PAGE>
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE
----
Plains Resources Inc. and Subsidiaries Consolidated Financial
Statements:
Report of Independent Accountants F-2
Consolidated Balance Sheets as of December 31, 1998 and 1997 F-3
Consolidated Statements of Operations for the years ended
December 31, 1998, 1997 and 1996 F-4
Consolidated Statements of Cash Flows for the years ended
December 31, 1998, 1997 and 1996 F-5
Consolidated Statements of Changes in Stockholders' Equity for
the years ended December 31, 1998, 1997 and 1996 F-6
Notes to Consolidated Financial Statements F-7
All other schedules are omitted because they are not applicable or the required
information is shown in the financial statements or notes thereto.
F-1
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and
Stockholders of Plains Resources Inc.
In our opinion, the consolidated financial statements listed in the accompanying
index present fairly, in all material respects, the financial position of Plains
Resources Inc. and its subsidiaries at December 31, 1998 and 1997, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 1998, in conformity with generally accepted
accounting principles. These financial statements are the responsibility of the
Company's management; our responsibility is to express an opinion on these
financial statements based on our audits. We conducted our audits of these
statements in accordance with generally accepted auditing standards which
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP
Houston, Texas
March 29, 1999, except as to Note 22 which is as of September 20, 1999.
F-2
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
<TABLE>
<CAPTION>
December 31,
------------------------------
1998 1997
------------ -------------
ASSETS
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents $ 6,544 $ 3,714
Accounts receivable 128,875 99,597
Inventory 42,520 22,802
Prepaid expenses and other 1,527 667
----------- ------------
Total current assets 179,466 126,780
----------- ------------
PROPERTY AND EQUIPMENT
Oil and natural gas properties - full cost method
Subject to amortization 596,203 498,038
Not subject to amortization 54,545 52,024
Crude oil pipeline, gathering and terminal assets 378,254 35,451
Other property and equipment 8,606 8,074
----------- ------------
1,037,608 593,587
Less allowance for depreciation, depletion and amortization (375,882) (180,279)
----------- ------------
661,726 413,308
----------- ------------
OTHER ASSETS 133,075 16,731
----------- ------------
$ 974,267 $ 556,819
=========== ============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and other current liabilities $ 170,985 $ 102,663
Interest payable 7,950 6,601
Royalties payable 4,211 5,016
Notes payable and other current obligations 10,261 18,511
----------- ------------
Total current liabilities 193,407 132,791
BANK DEBT 52,000 80,000
BANK DEBT OF A SUBSIDIARY 175,000 -
SUBORDINATED DEBT 202,427 202,661
OTHER LONG-TERM DEBT 2,556 3,067
OTHER LONG-TERM LIABILITIES 13,967 5,107
----------- ------------
639,357 423,626
----------- ------------
COMMITMENTS AND CONTINGENCIES (NOTE 13)
MINORITY INTEREST 173,461 -
----------- ------------
SERIES E CUMULATIVE CONVERTIBLE PREFERRED STOCK,
STATED AT LIQUIDATION PREFERENCE 88,487 -
----------- ------------
NON-REDEEMABLE PREFERRED STOCK, COMMON STOCK
AND OTHER STOCKHOLDERS' EQUITY
Series D Cumulative Convertible Preferred Stock, $1.00 par value, 46,600 shares
authorized, issued and outstanding, net of discount of $1,354,000 and $2,629,000
at December 31, 1998 and 1997, respectively 21,946 20,671
Common Stock, $.10 par value, 50,000,000 shares authorized; issued and outstanding
16,881,938 and 16,703,074 shares at December 31, 1998 and 1997, respectively 1,688 1,670
Additional paid-in capital 124,679 122,887
Accumulated deficit (75,351) (12,035)
----------- ------------
72,962 133,193
----------- ------------
$ 974,267 $ 556,819
=========== ============
</TABLE>
See notes to consolidated financial statements.
F-3
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except share data)
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1998 1997 1996
------------- ------------- -------------
REVENUES
<S> <C> <C> <C>
Oil and natural gas sales $ 102,754 $ 109,403 $ 97,601
Marketing, transportation, storage and terminalling revenues 1,129,689 752,522 531,698
Gain on formation of PAA (See Note 2) 60,815 - -
Interest and other income 834 319 309
------------- ------------- -------------
1,294,092 862,244 629,608
------------- ------------- -------------
EXPENSES
Production expenses 50,827 45,486 38,735
Marketing, transportation, storage and terminalling expenses 1,091,328 740,042 522,167
General and administrative 10,778 8,340 7,729
Depreciation, depletion and amortization 31,020 23,778 21,937
Reduction in carrying cost of oil and natural gas properties 173,874 - -
Interest expense 35,730 22,012 17,286
Litigation settlement - - 4,000
------------- ------------- -------------
1,393,557 839,658 611,854
------------- ------------- -------------
Income (loss) before income taxes, extraordinary item and
minority interest (99,465) 22,586 17,754
Minority interest 1,809 - -
------------- ------------- -------------
Income (loss) before income taxes and extraordinary item (101,274) 22,586 17,754
Income tax expense (benefit)
Current 862 352 -
Deferred (43,582) 7,975 (3,898)
------------- ------------- -------------
INCOME (LOSS) BEFORE EXTRAORDINARY ITEM (58,554) 14,259 21,652
EXTRAORDINARY ITEM:
Loss on early extinguishment of debt, net of tax benefit - - (5,104)
------------- ------------- -------------
NET INCOME (LOSS) (58,554) 14,259 16,548
Less: cumulative preferred stock dividends 4,762 163 -
------------- ------------- -------------
NET INCOME (LOSS) AVAILABLE TO COMMON
STOCKHOLDERS $ (63,316) $ 14,096 $ 16,548
============= ============= =============
Basic earnings per share:
Income (loss) before extraordinary item $ (3.77) $ 0.85 $ 1.32
Extraordinary item - - (0.31)
------------- ------------- -------------
Net income (loss) $ (3.77) $ 0.85 $ 1.01
============= ============= =============
Diluted earnings per share:
Income (loss) before extraordinary item $ (3.77) $ 0.77 $ 1.23
Extraordinary item - - (0.29)
------------- ------------- -------------
Net income (loss) $ (3.77) $ 0.77 $ 0.94
============= ============= =============
</TABLE>
See notes to consolidated financial statements.
F-4
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------
1998 1997 1996
------------ ------------ ------------
CASH FLOWS FROM OPERATING ACTIVITIES
<S> <C> <C> <C>
Net income (loss) $ (58,554) $ 14,259 $ 16,548
Items not affecting cash flows from operating activities:
Depreciation, depletion and amortization 31,020 23,778 21,937
Reduction in carrying costs of oil and natural gas properties 173,874 - -
Non-cash gain (See Note 2) (70,037) - -
Minority interest in income 1,809 - -
Loss on early extinguishment of debt, net of tax - - 5,104
Deferred income taxes (43,582) 7,975 (3,898)
Other non-cash items 90 221 251
Change in assets and liabilities from operating activities:
Accounts receivable 24,952 (9,518) (41,046)
Inventory (19,057) (18,239) 551
Purchase of pipeline linefill (3,904) - -
Prepaids and other (868) 128 (64)
Accounts payable and other current liabilities 410 9,858 37,296
Interest payable 1,467 1,494 977
Royalties payable 10 351 1,352
------------ ------------ ------------
Net cash provided by operating activities 37,630 30,307 39,008
------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES
Midstream acquisition (see Note 9):
Payment for acquisition of pipeline and related assets (392,528) - -
Payment for working capital (excluding cash received of $7,481) (1,498) - -
Payment for crude oil pipeline, gathering and terminal assets (8,131) (923) (1,850)
Cash received from the sale of oil and natural gas properties 131 2,667 3,066
Payment for acquisition, exploration and developments costs (80,318) (105,646) (53,011)
Payment for additions to other property and assets (1,078) (3,732) (701)
------------ ------------ ------------
Net cash used in investing activities (483,422) (107,634) (52,496)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt 570,560 266,905 263,723
Proceeds from short-term debt 31,750 39,000 -
Proceeds from sale of capital stock, options and warrants 828 1,104 1,785
Proceeds from issuance of preferred stock 85,000 - -
Proceeds from issuance of common units (See Note 2) 244,690 - -
Principal payments of long-term debt (423,560) (207,011) (248,144)
Principal payments of short-term debt (40,000) (21,000) -
Costs incurred to redeem long-term debt - - (6,468)
Debt issue and other costs incurred in connection with
acquisition (See Note 9) (6,138) - -
Debt issue and other costs incurred in connection with
public offering (See Note 2) (9,937) - -
Other (4,571) (474) (1,020)
------------ ------------ ------------
Net cash provided by financing activities 448,622 78,524 9,876
------------ ------------ ------------
Net increase (decrease) in cash and cash equivalents 2,830 1,197 (3,612)
Cash and cash equivalents, beginning of year 3,714 2,517 6,129
------------ ------------ ------------
Cash and cash equivalents, end of year $ 6,544 $ 3,714 $ 2,517
============ ============ ============
</TABLE>
See notes to consolidated financial statements.
F-5
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
(in thousands)
<TABLE>
<CAPTION>
Series D Series E
Cumulative Cumulative Additional Accumu-
Convertible Convertible Paid-In lated
Preferred Stock Preferred Stock Common Stock Capital Deficit
------------------------ ----------------------- ----------------------- ------------- ------------
Shares Amount Shares Amount Shares Amount
---------- ------------ ---------- ----------- ---------- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
BALANCE AT
DECEMBER 31, 1995 - $ - - $ - 16,179 $ 1,618 $ 118,090 $ (42,679)
Capital stock issued
upon exercise of
options and other - - - - 340 34 1,961 -
Net income for the year - - - - - - - 16,548
---------- ------------ ---------- ----------- ---------- ----------- ------------- -------------
BALANCE AT
DECEMBER 31, 1996 - - - - 16,519 1,652 120,051 (26,131)
Capital stock issued
upon exercise of
options and other - - - - 184 18 1,936 -
Issuance of preferred
stock and warrant
in connection with
an acquisition 47 20,508 - - - - 900 -
Dividends on
preferred stock - 163 - - - - - (163)
Net income for the year - - - - - - - 14,259
---------- ------------ ---------- ----------- ---------- ----------- ------------- -------------
BALANCE AT
DECEMBER 31, 1997 47 20,671 - - 16,703 1,670 122,887 (12,035)
Capital stock issued
upon exercise of
options and other - - - - 179 18 1,792 -
Issuance of
preferred stock - - 170 85,000 - - - -
Dividends on
preferred stock - 1,275 3 3,487 - - - (4,762)
Net loss for the year - - - - - - - (58,554)
---------- ------------ ---------- ----------- ---------- ----------- ------------- -------------
BALANCE AT
DECEMBER 31, 1998 47 $ 21,946 173 $ 88,487 16,882 $ 1,688 $ 124,679 $ (75,351)
========== ============ ========== =========== ========== =========== ============= =============
</TABLE>
See notes to consolidated financial statements.
F-6
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - ACCOUNTING POLICIES
Principles of Consolidation and Presentation
The consolidated financial statements include the accounts of Plains
Resources Inc. (the "Company"), its wholly-owned subsidiaries and Plains All
American Pipeline, L.P. ("PAA") in which the Company has an approximate 57%
ownership interest and serves as its sole general partner (See Note 2). For
financial statement purposes, the assets, liabilities and earnings of PAA are
included in the Company's consolidated financial statements, with the public
unitholders' interest reflected as a minority interest. All material
intercompany accounts and transactions have been eliminated. Certain
reclassifications have been made to the prior year statements to conform with
the current year presentation.
The Company is an independent energy company engaged in the acquisition,
exploitation, development, exploration and production of crude oil and natural
gas. Through its majority ownership in PAA, the Company is engaged in the
midstream activities of marketing, transportation, terminalling and storage of
crude oil. The Company's upstream oil and natural gas activities are focused in
California in the Los Angeles Basin (the "LA Basin"), the Arroyo Grande Field
and the Mt. Poso Field (collectively the "California Properties"), the Sunniland
Trend of South Florida (the "Sunniland Trend") and the Illinois Basin in
southern Illinois (the "Illinois Basin"). The Company's midstream activities are
concentrated in California, Texas, Oklahoma, Louisiana and the Gulf of Mexico.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Estimates made by management include: oil and natural gas
reserves, depreciation, depletion and amortization, including future abandonment
costs, income taxes and related valuation allowance and pension liabilities.
Although management believes these estimates are reasonable, actual results
could differ from these estimates.
Cash and Cash Equivalents
Cash and cash equivalents consist of all demand deposits and funds invested
in highly liquid instruments. The Company's cash management program results in
book overdraft balances which have been reclassified to current liabilities.
Inventory
Crude oil inventory is carried at the lower of cost, as adjusted for
deferred hedging gains and losses, or market value using an average cost method.
Materials and supplies inventory is stated at the lower of cost or market with
cost determined on a first-in, first-out method.
Oil and Natural Gas Properties
The Company follows the full cost method of accounting whereby all costs
associated with property acquisition, exploration, exploitation and development
activities are capitalized. Such costs include internal general and
administrative costs such as payroll and related benefits and costs directly
attributable to employees engaged in acquisition, exploration, exploitation and
development activities. General and administrative costs associated with
production, operations, marketing and general corporate activities are expensed
as incurred. These capitalized costs along with the Company's estimate of future
development and abandonment costs, net of salvage values and other
considerations, are amortized to expense by the unit-of-production method using
engineers' estimates of unrecovered proved oil and natural gas reserves. The
costs of unproved properties are excluded from amortization until the properties
are evaluated. Interest is capitalized on oil and natural gas properties not
subject to amortization and in the process of development. Proceeds from the
sale of properties are accounted for as reductions to capitalized costs unless
such sales involve a significant change in the relationship between costs and
the estimated value of proved reserves, in which case a gain or loss is
recognized. Unamortized costs of proved properties are subject to a ceiling
which limits such costs to the present value of estimated future cash flows from
proved oil and natural gas reserves of such properties reduced by future
operating expenses, development expenditures and abandonment costs (net of
salvage values), and estimated future income taxes thereon (the "Standardized
Measure") (See Note 18).
F-7
<PAGE>
Crude Oil Pipeline Gathering and Terminal Assets
Crude oil pipeline, gathering and terminal assets are recorded at cost and
consist primarily of (i) crude oil pipeline facilities (primarily the All
American Pipeline System and SJV Gathering System), (ii) crude oil terminal and
storage facilities (primarily the Cushing Terminal), and (iii) trucking
equipment, injection stations and other. Depreciation is computed using the
straight-line method over estimated useful lives of 5 to 40 years. Pipeline
facilities are depreciated over estimated useful lives of twenty-five to forty
years. Depreciation on the Cushing Terminal is provided based on a useful life
of forty years. Acquisitions and improvements are capitalized; maintenance and
repairs are expensed as incurred.
Other Property and Equipment
Other property and equipment is recorded at cost and consists primarily of
office furniture and fixtures and computer hardware and software. Acquisitions,
renewals, and betterments are capitalized; maintenance and repairs are expensed.
Depreciation is provided using the straight-line method over estimated useful
lives of three to seven years.
Pipeline Linefill
Pipeline linefill consists of crude oil linefill used to pack a pipeline
such that when an incremental barrel enters a pipeline it forces a barrel out at
another location. The Company owns approximately 5.0 million barrels of crude
oil that is used to maintain the All American Pipeline's linefill requirements.
Proceeds from the sale and repurchase of pipeline linefill are reflected as cash
flows from operating activities in the accompanying consolidated statements of
cash flows.
Debt Issue Costs
Costs incurred in connection with the issuance of long-term debt are
capitalized and amortized using the straight-line method over the term of the
related debt.
Federal and State Income Taxes
Income taxes are accounted for in accordance with Statement of Financial
Accounting Standards ("SFAS ") No. 109, Accounting for Income Taxes. SFAS 109
requires recognition of deferred tax liabilities and assets for the expected
future tax consequences of events that have been included in the financial
statements or tax returns. Under this method, deferred tax liabilities and
assets are determined based on the difference between the financial statement
and tax bases of assets and liabilities using tax rates in effect for the year
in which the differences are expected to reverse.
Marketing, Transportation, Storage and Terminalling Revenues
Gathering and marketing revenues are accrued at the time title to the
product sold transfers to the purchaser, which typically occurs upon receipt of
the product by the purchaser, and purchases are accrued at the time title to the
product purchased transfers to the Company, which typically occurs upon receipt
of the product by the Company. Except for crude oil purchased from time to time
as inventory to service the needs of its terminalling and storage customers and
working requirements of third party pipelines, the Company's policy is to
purchase only crude oil for which it has a market to sell and to structure its
sales contracts so that crude oil price fluctuations do not materially affect
the gross margin which it receives. As the Company purchases crude oil, it
establishes a margin by selling crude oil for physical delivery to third party
users, such as independent refiners or major oil companies, or by entering into
a future delivery obligation with respect to futures contracts on the New York
Mercantile Exchange ("NYMEX"). Through these transactions, the Company seeks
to maintain a position that is substantially balanced between crude oil
purchases and sales and future delivery obligations. Terminalling and storage
revenues are recognized at the time service is performed. As a regulated
interstate pipeline, revenues for the transportation of crude oil on the All
American Pipeline is recognized based upon Federal Energy Regulatory Commission
("FERC") and the Public Utilities Commission of the State of California ("CPUC")
filed tariff rates and the related transported volume. Tariff revenue is
recognized at the time such volume is delivered.
Hedging
The Company utilizes various derivative instruments to hedge its exposure
to price fluctuations on oil and natural gas transactions. The derivative
instruments used consist primarily of futures and option contracts traded on the
NYMEX and crude oil swap contracts entered into with financial institutions.
These instruments are utilized to hedge transactions which are based on NYMEX
oil and gas prices; therefore, a high correlation exists between the hedged item
and the hedge contract. The Company has entered into interest rate swaps to
manage the interest rate exposure on certain of its long-term debt.
F-8
<PAGE>
Recognized gains and losses on hedge contracts are reported as a component
of the related transaction. Results for hedging transactions are reflected in
oil and natural gas sales to the extent related to the Company's oil and natural
gas production and in marketing, transportation, storage and terminalling
revenues to the extent related to such activities. Cash flows from hedging
activities are included in operating activities in the Consolidated Statements
of Cash Flows. Net deferred gains and losses on futures contracts, including
closed futures contracts, entered into to hedge anticipated crude oil purchases
and sales are included in accounts payable and other current liabilities in the
Consolidated Balance Sheets. Deferred gains or losses from inventory hedges are
included as part of the inventory cost and recognized when the related inventory
is sold. Crude oil swap contracts have no carrying value and therefore are not
reflected in the Consolidated Balance Sheets. Amounts paid or received from
interest rate swaps are charged or credited to interest expense over the term of
the swap.
Stock Options
In October 1995, the Financial Accounting Standards Board ("FASB") issued
Statement No. 123 ("SFAS 123"), Accounting for Stock Based Compensation. In
accordance with the provisions of SFAS No. 123, the Company applies APB
Opinion 25 and related interpretations in accounting for its stock option plans
(See Note 12).
Recent Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities ("FAS 133"). FAS 133 is effective for all
fiscal years beginning after June 15, 1999 (January 1, 2000 for the Company).
FAS 133 requires that all derivative instruments be recorded on the balance
sheet at their fair value. Changes in the fair value of derivatives are recorded
each period in current earnings or other comprehensive income, depending on
whether a derivative is designated as part of a hedge transaction and, if it is,
the type of hedge transaction. For fair-value hedge transactions in which the
Company is hedging changes in an asset's, liability's, or firm commitment's fair
value, changes in the fair value of the derivative instrument will generally be
offset in the income statement by changes in the hedged item's fair value. For
cash-flow hedge transactions in which the Company is hedging the variability of
cash flows related to a variable-rate asset, liability, or a forecasted
transaction, changes in the fair value of the derivative instrument will be
reported in other comprehensive income. The gains and losses on the derivative
instrument that are reported in other comprehensive income will be reclassified
as earnings in the periods in which earnings are affected by the variability of
the cash flows of the hedged item. The Company has not yet determined the impact
that the adoption of FAS 133 will have on its earnings or financial position.
In November 1998, the Emerging Issues Task Force ("EITF") released Issue
No. 98-10, "Accounting for Energy Trading and Risk Management Activities".
EITF 98-10 deals with entities that enter into derivatives and other third-party
contracts for the purchase and sale of a commodity in which they normally do
business (for example, crude oil and natural gas). The EITF reached a consensus
that energy trading contracts should be measured at fair value determined as of
the balance sheet date with the gains and losses included in earnings and
separately disclosed in the financial statements or footnotes thereto. The EITF
acknowledged that determining whether or when an entity is involved in energy
trading activities is a matter of judgment that depends on the relevant facts
and circumstances. As such, certain factors or indicators have been identified
by the EITF which should be considered in evaluating whether an operation's
energy contracts are entered into for trading purposes. EITF 98-10 is required
to be applied to financial statements issued by the Company beginning in 1999.
The adoption of this consensus is not expected to have a material impact on the
Company's results of operations or financial position.
NOTE 2 - PAA - INITIAL PUBLIC OFFERING AND CONCURRENT TRANSACTIONS
- ------------------------------------------------------------------
The Company's midstream activities are conducted through PAA. PAA was
formed during 1998 to acquire and operate the business and assets of the
Company's wholly-owned midstream subsidiaries (the "Plains Midstream
Subsidiaries"). Plains All American Inc. ("PAAI" or the "General Partner"), a
wholly owned subsidiary of the Company, is the general partner of PAA.
On November 23, 1998, PAA completed an initial public offering (the "IPO")
of 13,085,000 common units representing limited partner interests (the "Common
Units") in PAA and received therefrom net proceeds of approximately $244.7
million. Concurrently with the closing of the IPO, certain transactions
described in the following paragraphs were consummated in connection with the
formation of PAA. Such transactions and the transactions which occurred in
conjunction with the IPO are referred to herein as the "Transactions".
Certain of the Plains Midstream Subsidiaries were merged into the Company,
which sold the assets of these subsidiaries to PAA in exchange for $64.1 million
and the assumption of $11 million of related indebtedness. At the same time, the
General Partner conveyed all of its interest in the All American Pipeline and
the SJV Gathering System, which it purchased in July 1998 for approximately $400
million (See Note 9), to PAA in exchange for (i) 6,974,239 Common Units,
10,029,619 Subordinated
F-9
<PAGE>
Units and an aggregate 2% general partner interest in PAA, (ii) the right to
receive Incentive Distributions; and (iii) the assumption by PAA of $175 million
of indebtedness incurred by the General Partner in connection with the
acquisition of the All American Pipeline and the SJV Gathering System.
In addition to the $64.1 million paid to the Company, PAA distributed
approximately $177.6 million to the General Partner and used approximately $3
million of the remaining proceeds to pay expenses incurred in connection with
the Transactions. The General Partner used $121.0 million of the cash
distributed to it to retire the remaining indebtedness incurred in connection
with the acquisition of the All American Pipeline and the SJV Gathering System
and to pay other costs associated with the transactions. The balance, $56.6
million, was distributed to the Company, which used the cash to repay
indebtedness and for other general corporate purposes.
In addition, concurrently with the closing of the IPO, PAA entered into a
$225 million bank credit agreement (the "Bank Credit Agreement") that includes
a $175 million term loan facility (the "Term Loan Facility") and a $50 million
revolving credit facility (the "PAA Revolving Credit Facility") (See Note 4).
During 1998, the Company recognized a pretax gain (net of approximately
$9.2 million in formation related expenses) in connection with the formation of
PAA. Such gain is the result of an increase in the book value of the Company's
equity in PAA to reflect their proportionate share of the underlying net assets
of PAA due to the sale of units in the IPO. The formation related expenses
consist primarily of amounts due to certain key employees in connection with the
successful formation of PAA, debt prepayment penalties and legal fees.
NOTE 3 - INVENTORY AND OTHER ASSETS
- -----------------------------------
Inventory consists of the following:
December 31,
---------------------------
1998 1997
------------ ------------
(in thousands)
Crude oil $ 37,702 $ 18,986
Materials and supplies 4,818 3,816
------------ ------------
$ 42,520 $ 22,802
============ ============
At December 31, 1998 and 1997, approximately 76% and 77%, respectively, of
the crude oil inventory volumes were hedged with NYMEX futures contracts or
short-term physical delivery contracts. The unhedged inventory is comprised of
working inventory and linefill primarily at the Cushing Terminal.
Other assets consist of the following:
December 31,
-------------------------------
1998 1997
--------------- --------------
(in thousands)
Pipeline linefill $ 54,511 $ -
Deferred tax asset (See Note 7) 47,785 796
Land 8,853 8,853
Debt issue costs 18,668 8,718
Other 8,245 2,776
--------------- --------------
139,393 21,143
Accumulated amortization (4,987) (4,412)
--------------- --------------
$133,075 $ 16,731
=============== ==============
F-10
<PAGE>
NOTE 4 - LONG-TERM DEBT AND CREDIT FACILITIES
- ---------------------------------------------
Long-term debt consists of the follows:
<TABLE>
<CAPTION>
December 31,
--------------------------
1998 1997
------------ ------------
(in thousands)
<S> <C> <C>
Revolving Credit Facility, bearing interest at weighted
average interest rates of 6.9% and 7.3%, at
December 31, 1998 and 1997, respectively $ 52,000 $ 80,000
PAA Bank Credit Agreement, bearing interest
at 6.75% at December 31, 1998. 175,000 -
10.25% Senior Subordinated Notes, due 2006, net of
unamortized premium of $2.4 million and $2.7 million
at December 31, 1998 and 1997, respectively 202,427 202,661
Other long-term debt 3,067 3,578
------------ ------------
Total long-term debt 432,494 286,239
Less current maturities (511) (511)
------------ ------------
$ 431,983 $ 285,728
============ ============
</TABLE>
Revolving Credit Facility
The Company has a $225 million revolving credit facility (the "Revolving
Credit Facility") with a group of banks (the "Lenders"). The Revolving Credit
Facility is guaranteed by all of the Company's upstream subsidiaries and is
collateralized by the oil and gas properties of the Company and the guaranteeing
subsidiaries and the stock of all upstream subsidiaries. The borrowing base
under the Revolving Credit Facility at December 31, 1998, is $225 million and is
subject to redetermination from time to time by the Lenders in good faith, in
the exercise of the Lenders' sole discretion, and in accordance with customary
practices and standards in effect from time to time for oil and natural gas
loans to borrowers similar to the Company. Such borrowing base may be affected
from time to time by the performance of the Company's oil and natural gas
properties and changes in oil and natural gas prices. The Company incurs a
commitment fee of 3/8% per annum on the unused portion of the borrowing base.
The Revolving Credit Facility, as amended, matures on July 1, 2000, at which
time the remaining outstanding balance converts to a term loan which is
repayable in twenty equal quarterly installments commencing October 1, 2000,
with a final maturity of July 1, 2005. The Revolving Credit Facility bears
interest, at the Company's option of either LIBOR plus 1 3/8% or Base Rate (as
defined therein). At December 31, 1998, outstanding borrowings under the
Revolving Credit Facility were $52 million.
The Revolving Credit Facility contains covenants which, among other things,
prohibit the payment of cash dividends, limit the amount of consolidated debt,
limit the Company's ability to make certain loans and investments, and provides
that the Company must maintain a Current Ratio, as defined, of 1:1.
10.25% Senior Subordinated Notes Due 2006
The Company has $200 million principal amount of 10.25% Senior
Subordinated Notes Due 2006 (the "10.25% Notes") outstanding which bear a coupon
rate of 10.25% and consist of (i) Series A - $.5 million principal amount; (ii)
Series B - $149.5 million principal amount; (iii) Series C - $50,000 principal
amount and (iv) Series D - $49.95 million principal amount.
The Series A & B 10.25% Notes were issued in 1996 at 99.38% of par to
yield 10.35%. Proceeds from the sale of the Series A and B 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 $42 million of
bridge bank indebtedness which was incurred in December 1995 in connection with
the acquisition of the Company's Illinois Basin properties. The 12% Notes were
redeemed in April 1996, and the Company recognized an extraordinary loss of $8.5
million, $5.1 million net of deferred income taxes, in connection therewith.
The Series C & D 10.25% Notes were issued in 1997 at approximately 107% of
par to yield a minimum yield to worst of 8.79%, or 9.03% to maturity. Proceeds
from the sale of the Series C & D 10.25% Notes, net of offering costs, were
approximately $53 million and were used to reduce the balance on the Revolving
Credit Facility.
F-11
<PAGE>
The 10.25% Notes are redeemable, at the option of the Company, on or after
March 15, 2001 at 105.13% of the principal amount thereof, at decreasing prices
thereafter prior to March 15, 2004, and thereafter at 100% of the principal
amount thereof 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 & B 10.25% Notes and up to $15 million in principal amount of the
Series C & D 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 dispositions 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.
PAA Credit Facilities
Bank Credit Agreement.
PAA has a $225 million Bank Credit Agreement which consists of the $175
million Term Loan Facility and the $50 million PAA Revolving Credit Facility.
The $50 million PAA Revolving Credit Facility is used for capital improvements
and working capital and general business purposes and contains a $10 million
sublimit for letters of credit issued for general corporate purposes. The Bank
Credit Agreement is secured by a lien on substantially all of the assets of PAA.
The Term Loan Facility bears interest at PAA's option at either (i) the
Base Rate, as defined, or (ii) reserve-adjusted LIBOR plus an applicable margin.
PAA has two 10-year interest rate swaps (subject to cancellation by the counter
party after seven years) aggregating $175 million notional principal amount,
which fix the LIBOR portion of the interest rate (not including the applicable
margin) at a weighted average rate of approximately 5.24%. Borrowings under the
Revolving Credit Facility bear interest at PAA's option at either (i) the Base
Rate, as defined, or (ii) reserve-adjusted LIBOR plus an applicable margin. PAA
incurs a commitment fee on the unused portion of the PAA Revolving Credit
Facility and, with respect to each issued letter of credit, an issuance fee.
At December 31, 1998, PAA had $175 million outstanding under the Term Loan
Facility, which amount represents indebtedness assumed from the General Partner.
The Term Loan Facility matures in seven years, and no principal is scheduled for
payment prior to maturity. The Term Loan Facility may be prepaid at any time
without penalty. The PAA Revolving Credit Facility expires in two years. All
borrowings for working capital purposes outstanding under the PAA Revolving
Credit Facility must be reduced to no more than $8 million for at least 15
consecutive days during each fiscal year. At December 31, 1998, there are no
amounts outstanding under the PAA Revolving Credit Facility.
Letter of Credit Facility
Simultaneously with the IPO, PAA entered into a $175 million secured letter
of credit and borrowing facility with BankBoston, N.A. ("BankBoston"), ING
(U.S.) Capital Corporation ("ING Baring") and certain other lenders (the
"Letter of Credit Facility"), which replaced the existing facility for the
benefit of one of the Plains Midstream Subsidiaries. The purpose of the Letter
of Credit Facility is to provide (i) standby letters of credit to support the
purchase and exchange of crude oil for resale and (ii) borrowings to finance
crude oil inventory which has been hedged against future price risk or has been
designated as working inventory. The Letter of Credit Facility is collateralized
by a lien on substantially all of the assets of PAA. Aggregate availability
under the Letter of Credit Facility for direct borrowings and letters of credit
is limited to a borrowing base which is determined monthly based on certain
current assets and current liabilities of PAA, primarily crude oil inventory and
accounts receivable and accounts payable related to the purchase and sale of
crude oil. At December 31, 1998, the borrowing base under the Letter of Credit
Facility was approximately $175 million.
The Letter of Credit Facility has a $40 million sublimit for borrowings to
finance crude oil purchased in connection with operations at PAA's crude oil
terminal and storage facilities. All purchases of crude oil inventory financed
are required to be hedged against future price risk on terms acceptable to the
lenders. At December 31, 1998, approximately $9.8 million was
F-12
<PAGE>
outstanding under the sublimit. At December 31, 1997, approximately $18 million
in borrowings was outstanding under a similar sublimit under a previous credit
facility.
Letters of credit under the Letter of Credit Facility are generally issued
for up to 70 day periods. Borrowings bear interest at PAA's option at either (i)
the Base Rate (as defined) or (ii) reserve-adjusted LIBOR plus the applicable
margin. PAA incurs a commitment fee on the unused portion of the borrowing
sublimit under the Letter of Credit Facility and an issuance fee for each letter
of credit issued. The Letter of Credit Facility expires July 31, 2001.
At December 31, 1998 and 1997, there were outstanding letters of credit of
approximately $62 million and $38 million, respectively, issued under the Letter
of Credit Facility and a previous letter of credit facility, respectively. To
date, no amounts have been drawn on such letters of credit issued by PAA or the
Plains Midstream Subsidiaries.
Both the Letter of Credit Facility and the Bank Credit Agreement contain a
prohibition on distributions on, or purchases or redemption's of, Units if any
Default or Event of Default (as defined) is continuing. In addition, both
facilities contain various covenants limiting the ability of PAA to (i) incur
indebtedness, (ii) grant certain liens, (iii) sell assets in excess of certain
limitations, (iv) engage in transactions with affiliates, (v) make investments,
(vi) enter into hedging contracts and (vii) enter into a merger, consolidation
or sale of its assets. In addition, the terms of the Letter of Credit Facility
and the Bank Credit Agreement require PAA to maintain (i) a Current Ratio (as
defined) of 1.0 to 1.0; (ii) a Debt Coverage Ratio (as defined) which is not
greater than 5.0 to 1.0; (iii) an Interest Coverage Ratio (as defined) which is
not less than 3.0 to 1.0; (iv) a Fixed Charge Coverage Ratio (as defined) which
is not less than 1.25 to 1.0; and (v) a Debt to Capital Ratio (as defined) of
not greater than .60 to 1.0. In both the Letter of Credit Facility and the Bank
Credit Agreement, a Change in Control (as defined) of the Company constitutes an
Event of Default.
Maturities
The aggregate amount of maturities of all long-term indebtedness for the
next five years is: 1999 - $.5 million, 2000 - $3.1 million, 2001 - $10.9
million, 2002 - $10.9 million and 2003 - $10.9 million.
NOTE 5 - CAPITAL STOCK
- ----------------------
Common Stock
The Company has authorized capital stock consisting of 50 million shares of
common stock, $.10 par value, and 2 million shares of preferred stock, $1.00 par
value. At December 31, 1998, there were 16.9 million shares of common stock
("Common Stock") issued and outstanding and 219,424 shares of preferred stock
outstanding.
Stock Warrants and Options
At December 31, 1998, the Company had warrants outstanding which entitle
the holders thereof to purchase an aggregate one million shares of Common Stock.
Per share exercise prices and expiration dates for the warrants are as follows:
750,000 shares at $6.00 expiring in 1999, 100,000 shares at $7.50 expiring in
2000 and 150,000 shares at $25.00 expiring in 2002.
The Company has various stock option plans for its employees and directors
(See Note 12).
Series D Cumulative Convertible Preferred Stock
In November 1997, the Company issued 46,600 shares of Series D Cumulative
Convertible Preferred Stock (the "Series D Preferred Stock") in connection with
the acquisition of the Arroyo Grande Field (See Note 8). The Series D Preferred
Stock has an aggregate stated value of $23.3 million and is redeemable at the
Company's option at 140% of stated value. If not previously redeemed or
converted, the Series D Preferred Stock will automatically convert into 932,000
shares of Common Stock in 2012. Each share of the Series D Preferred Stock has a
stated value of $500 and is convertible into Common Stock at a ratio of $25 of
stated value for each share of Common Stock to be issued. Commencing January 1,
2000, the Series D Preferred Stock will bear an annual dividend of $30 per
share. Prior to such date, no dividends will accrue. The Series D Preferred
Stock was initially recorded at $20.5 million, a discount of $2.8 million from
the stated value of $23.3 million. This discount will be amortized to retained
earnings during the two year period dividends do not accrue.
F-13
<PAGE>
Redeemable Preferred Stock
On July 29, 1998, the Company sold in a private placement 170,000 shares of
its Series E Preferred Stock for $85 million. Each share of the Series E
Preferred Stock has a stated value of $500 per share and bears a dividend of
9.5% per annum. Dividends are payable semi-annually in either cash or additional
shares of Series E Preferred Stock at the Company's option and are cumulative
from the date of issue. Each share of Series E Preferred Stock is convertible
into 27.78 shares of Common Stock (an initial effective conversion price of
$18.00 per share) and in certain circumstances may be converted at the Company's
option into Common Stock if the average trading price for any thirty-day trading
period is equal to or greater than $21.60 per share. The Series E Preferred
Stock is redeemable at the option of the Company after March 31, 1999, at 110%
of stated value and at declining amounts thereafter. If not previously redeemed
or converted, the Series E Preferred Stock is required to be redeemed in 2012.
Proceeds from the Series E Preferred Stock were used to fund a portion of
the Company's capital contribution to PAAI to acquire all of the outstanding
capital stock of the Celeron Companies (See Note 9).
On October 1, 1998, the Company paid a dividend on the Series E Preferred
Stock for the period from July 29, 1998 through September 30, 1998. The dividend
amount of approximately $1.4 million was paid by issuing 2,824 additional shares
of the Series E Preferred Stock. After payment of such dividend, there were
172,824 shares of the Series E Preferred Stock outstanding with a liquidation
value, including accrued dividends through December 31, 1998, of approximately
$88.5 million.
NOTE 6 - EARNINGS PER SHARE
- ---------------------------
In February 1997, the FASB issued Statement of Financial Accounting
Standards No. 128 ("SFAS 128"), Earnings Per Share ("EPS"). Basic EPS excludes
dilutive securities and is computed by dividing income available to common
stockholders by the weighted-average number of common shares outstanding for the
period. Diluted EPS reflects the potential dilution that could occur if dilutive
securities were converted into common stock and is computed similarly to fully
diluted EPS pursuant to previous accounting pronouncements.
The following is a reconciliation of the numerators and the denominators of
the basic and diluted EPS computations for income from continuing operations for
the years ended December 1998, 1997 and 1996, as required by SFAS 128. All prior
period EPS data has been restated in accordance with the provisions of SFAS 128.
<TABLE>
<CAPTION>
For the Year Ended December 31,
-------------------------------------------------------------------------------------------------------
1998 1997 1996
---------------------------------- ---------------------------------- ---------------------------------
Income Shares Per Income Shares Per Income Shares Per
(Numera- (Denomi- Share (Numera- (Denomi- Share (Numera- (Denomi- Share
tor) nator) Amount tor) nator) Amount tor) nator) Amount
------------ ----------- --------- ------------ ---------- ---------- ----------- ---------- ---------
(in thousands)
<S> <C> <C> <C>
Income before
extraordinary item $ (63,316) $ 14,259 $ 21,652
Less: preferred
stock dividends - (163) -
------------ ------------ -----------
Income available
to common
stockholders (63,316) 16,816 $ (3.77) 14,096 16,603 $ 0.85 21,652 16,384 $ 1.32
========= ========== =========
Effect of dilutive
securities:
Employee stock
options - - - 1,085 - 839
Warrants - - - 516 - 421
------------ ----------- ------------ ---------- ----------- ----------
Income available
to common
stockholders
assuming
dilution $ (63,316) 16,816 $ (3.77) $ 14,096 18,204 $ 0.77 $ 21,652 17,644 $ 1.23
============ =========== ========= ============ ========== ========== =========== ========== =========
</TABLE>
Certain options and warrants to purchase shares of Common Stock were not
included in the computations of diluted EPS because the exercise prices were
greater than the average market price of the Common Stock during the periods of
the EPS calculations, resulting in antidilution. In addition, the Series E
Preferred Stock, which was issued during 1998, and the Company's
F-14
<PAGE>
Series D Preferred Stock, which was issued during 1997, is convertible into
Common Stock but was not included in the computation of diluted EPS because the
effect was antidilutive. See Notes 5 and 12 for additional information
concerning outstanding options and warrants.
NOTE 7 - INCOME TAXES
- ---------------------
The Company's deferred income tax assets (liabilities) at December 31, 1998
and 1997, consist of the tax effect of income tax carryforwards and differences
related to the timing of recognition of certain types of costs incurred in both
the Company's upstream oil and gas operations and its midstream activities as
follows:
December
-------------------------
1998 1997
------------ -----------
U.S. Federal
Deferred tax assets:
Net operating losses $ 48,911 $ 60,055
Percentage depletion 2,450 2,450
Tax credit carryforwards 1,614 1,010
Other 1,354 335
------------ -----------
54,329 63,850
Deferred tax liabilities:
Oil and gas acquisition, exploration
and development costs - (53,873)
Marketing and pipeline depreciation
and related adjustments (3,758) (2,243)
------------ -----------
Net deferred tax asset 50,571 7,734
Valuation allowance (2,786) (6,938)
------------ -----------
$ 47,785 $ 796
============ ===========
States
Deferred tax liability $ (3,714) $ (958)
============ ===========
At December 31, 1998, the Company has a net deferred tax asset of
$47.8 million. Management believes that it is more likely than not that it will
generate taxable income sufficient to realize such asset based on certain tax
planning strategies available to the Company. As an example, the Company,
through its existing ownership in PAA which is publicly traded, could generate
sufficient taxable income to utilize the tax asset existing at December 31,
1998. Therefore, the Company has concluded that the valuation allowance is
adequate. In the fourth quarter of 1998, as a result of the formation of PAA,
significant taxable income was generated allowing the Company to utilize certain
net operating losses ("NOLs") generated in past years. The use of such NOLs has
permitted the Company to revise the valuation allowance previously associated
with a portion of those NOLs. The benefit of NOL carryforwards recognized during
the current year totaled approximately $5.0 million.
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. The remaining deferred tax asset was not recognized primarily 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.
At December 31, 1998, the Company had carryforwards of approximately $139.7
million of regular tax NOLs, $7.0 million of statutory depletion, $.3 million of
ITC and $1.3 million of alternative minimum tax ("AMT") credit. Utilization of
a portion of the ITC carryforwards is limited to certain companies within the
consolidated group. At December 31, 1998, the Company had approximately $128.3
million of AMT NOL carryforwards available as a deduction against future AMT
income. The NOL carryforwards expire from 2003 through 2011.
F-15
<PAGE>
Set forth below is a reconciliation between the income tax provision
computed at the United States statutory rate on income before income taxes and
the income tax provision per the accompanying Consolidated Statements of
Operations:
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------
1998 1997 1996
------------ ------------ -----------
(in thousands)
<S> <C> <C> <C>
U.S. federal income tax provision at statutory rate $ (35,446) $ 7,905 $ 6,214
State income taxes (5,094) 376 888
Valuation allowance adjustment (4,987) - (11,000)
Full cost ceiling test limitation 2,903 - -
Other (96) 46 -
------------ ------------ -----------
Income taxes on income before extraordinary item (42,720) 8,327 (3,898)
Income tax benefit allocated to extraordinary item - - (3,403)
------------ ------------ -----------
Income tax (benefit) provision $ (42,720) $ 8,327 $ (7,301)
============ ============ ===========
</TABLE>
In accordance with certain provisions of the Tax Reform Act of 1986, a
change of greater than 50% of the beneficial ownership of the Company within a
three-year period (an "Ownership Change") will place an annual limitation on the
Company's ability to utilize its existing tax carryforwards. Under the Final
Treasury Regulations issued by the Internal Revenue Service, the Company does
not believe that an Ownership Change has occurred as of December 31, 1998.
NOTE 8 - UPSTREAM ACQUISITIONS AND DISPOSITIONS
- -----------------------------------------------
During 1998, the Company acquired the Mt. Poso Field from Aera Energy LLC
for approximately $7.7 million. The field is located approximately 27 miles
north of Bakersfield, California, in Kern County. At acquisition, the field was
producing 1,200 barrels of oil per day of 15-17 degree API gravity crude and
added approximately 8 million barrels of oil equivalent to the Company's proved
reserves.
In March 1997, the Company completed the acquisition of Chevron USA's
("Chevron") interest in the Montebello Field for $25 million, effective
February 1, 1997. The assets acquired consist of a 100% working interest and a
99.2% net revenue interest in 55 producing oil wells and related facilities and
also include approximately 450 acres of surface fee land. At the acquisition
date, the Montebello Field, which is located approximately 15 miles from the
Company's existing California operations, was producing approximately 800
barrels of oil and 800 Mcf of gas per day and added approximately 23 million
barrels of oil equivalent to the Company's proved reserves. The acquisition was
funded with proceeds from the Revolving Credit Facility.
In November 1997, the Company acquired a 100% working interest and a 97%
net revenue interest in the Arroyo Grande Field in San Luis Obispo County,
California, from subsidiaries of Shell Oil Company ("Shell"). The assets
acquired include surface and development rights to approximately 1,000 acres
included in the 1,500 acre unit. At the acquisition date, the Arroyo Grande
Field was producing approximately 1,600 barrels of 14 (degrees) API gravity oil
per day from 70 wells and added approximately 20 million barrels of oil
equivalent to the Company's proved reserves.
The aggregate purchase price of $22.1 million consisted of rights to a
non-producing property interest conveyed to Shell, the issuance of 46,600 shares
of Series D Preferred Stock with an aggregate stated value of $23.3 million and
a 5 year warrant to purchase 150,000 shares of Common Stock at $25 per share. No
proved reserves had been assigned to the rights to the property interest
conveyed.
During 1997 and 1996, the Company sold certain non-strategic oil and
natural gas properties located primarily in Louisiana and Utah for net proceeds
of approximately $2.7 million and $3.1 million, respectively.
NOTE 9 - MIDSTREAM ACQUISITION
- ------------------------------
On July 30, 1998, PAAI, a wholly owned unrestricted subsidiary of the
Company, as defined in the Indentures for the 10.25% Senior Subordinated Notes,
acquired all of the outstanding capital stock of the All American Pipeline
Company, Celeron Gathering Corporation and Celeron Trading & Transportation
Company (collectively the "Celeron Companies") from Wingfoot Ventures Seven,
Inc., a wholly-owned subsidiary of The Goodyear Tire & Rubber Company
("Goodyear") for approximately $400 million, including transaction costs. The
principal assets of the entities acquired include the All American Pipeline
System,
F-16
<PAGE>
a 1,233-mile crude oil pipeline extending from California to Texas, and a
45-mile crude oil gathering system in the San Joaquin Valley of California, as
well as other assets related to such operations.
Financing for the acquisition was provided through (i) PAAI's $325 million,
limited recourse bank facility with ING (U.S.) Capital Corporation, BankBoston,
N.A. and other lenders (the "PAAI Credit Facility") (See Note 4) and (ii) an
approximate $114 million capital contribution to PAAI by the Company.
Approximately $29 million of such capital contribution was funded by cash flow
and the Revolving Credit Facility and the remaining $85 million was provided by
the issuance of the Series E Preferred Stock (See Note 5).
The assets, liabilities and results of operations of the Celeron Companies
are included in the Consolidated Financial Statements of the Company effective
July 30,1998. The following unaudited pro forma information is presented to show
pro forma revenues, net loss and net loss per share as if the acquisition
occurred on January 1, 1997.
Year Ended December 31,
----------------------------------
1998 1997
--------------- --------------
(in thousands,
except per share data)
Revenues $ 1,731,746 $ 1,854,562
=============== ==============
Net loss $ (51,110) $ (6,067)
=============== ==============
Net loss per share:
Basic $ (3.60) $ (0.86)
=============== ==============
Diluted $ (3.60) $ (0.86)
=============== ==============
The pro forma net loss for the year ended December 31, 1997, includes a
non-cash impairment charge of $64.2 million related to the writedown of pipeline
assets and linefill by Wingfoot in connection with the sale of Wingfoot by
Goodyear to the Company. Based on the Company's purchase price allocation to
property and equipment and pipeline linefill, an impairment charge would not
have been required had the Company actually acquired Wingfoot effective
January 1, 1997. Excluding this impairment charge, the Company's pro forma net
income for 1997 would have been $33.1 million, or $1.36 per share.
The acquisition was accounted for utilizing the purchase method of
accounting and the purchase price was allocated in accordance with Accounting
Principles Board Opinion No. 16 as follows (in thousands):
Crude oil pipeline, gathering and terminal assets $392,528
Other assets (debt issue costs) 6,138
Net working capital items (excluding cash received of $7,481) 1,498
------------
Cash paid $400,164
============
NOTE 10 - RELATED PARTY TRANSACTIONS
- -------------------------------------
In conjunction with the IPO, the Company entered into various agreements
with PAA, including (i) the Omnibus Agreement, providing for the resolution of
certain conflicts arising from the conduct of PAA and the Company of related
businesses and for the General Partner's indemnification of PAA for certain
matters and (ii) the Crude Oil Marketing Agreement which provides for the
marketing by PAA of the Company's crude oil production.
PAA does not directly employ any persons to manage or operate its business.
These functions are provided by employees of the General Partner and the
Company. The General Partner does not receive a management fee or other
F-17
<PAGE>
compensation in connection with its management of PAA. PAA reimburses the
General Partner and the Company for all direct and indirect costs of services
provided, including the costs of employee, officer and director compensation and
benefits properly allocable to PAA, and all other expenses necessary or
appropriate to conduct the business of, and allocable to PAA. The PAA
Partnership Agreement provides that the General Partner will determine the
expenses that are allocable to PAA in any reasonable manner determined by the
General Partner in its sole discretion. Total costs reimbursed to the General
Partner and the Company by PAA were approximately $.5 million for 1998. Such
costs include, (i) allocated personnel costs (such as salaries and employee
benefits) of the personnel providing such services, (ii) rent on office space
allocated to the General Partner in the Company's offices in Houston, Texas and
(iii) out-of-pocket expenses related to the providing of such services.
PAAI adopted its 1998 Long-Term Incentive Plan (the "Long-Term Incentive
Plan") for employees and directors of PAAI and its affiliates who perform
services for PAA. The Long-Term Incentive Plan consists of two components, a
restricted unit plan (the "Restricted Unit Plan") and a unit option plan (the
"Unit Option Plan"). The Long-Term Incentive Plan currently permits the grant
of Restricted Units and Unit Options covering an aggregate of 975,000 Common
Units. The plan is administered by the Compensation Committee of PAAI's Board of
Directors.
Restricted Unit Plan. A Restricted Unit is a "phantom" unit that entitles
the grantee to receive a Common Unit upon the vesting of the phantom unit.
Approximately 500,000 Restricted Units were granted upon consummation of the IPO
to employees of PAAI. In general, Restricted Units granted to employees during
the Subordination Period (as defined in the PAA Partnership Agreement) will vest
only upon, and in the same proportion as, the conversion of Subordinated Units
to Common Units. PAAI will be entitled to reimbursement by PAA for the cost
incurred in acquiring such Common Units.
Unit Option Plan. The Unit Option Plan currently permits the grant of
options ("Unit Options") covering Common Units. No grants will initially be
made under the Unit Option Plan. The Compensation Committee may, in the future,
determine to make grants under such plan to employees and directors containing
such terms as the Committee shall determine.
In addition to the grants made under the Restricted Unit Plan described
above, PAAI agreed to transfer approximately 325,000 of its affiliates' Common
Units to certain key employees of the General Partner (the "Transaction
Grants"). Generally, approximately 72,000 of such Common Units will vest in each
of the years ending December 31, 1999, 2000 and 2001 if the Operating Surplus
generated in such year equals or exceeds the amount necessary to pay the minimum
quarterly distribution ("MQD") on all outstanding Common Units and the related
distribution on the general partner interest. If a tranche of Common Units does
not vest in a particular year, such Common Units will vest at the time the
Common Unit Arrearages for such year has been paid. In addition, approximately
36,000 of such Common Units will vest in each of the years ending December 31,
1999, 2000 and 2001 if the Operating Surplus generated in such year exceeds the
amount necessary to pay the MQD on all outstanding Common Units and Subordinated
Units and the related distribution on the general partner interest. Any Common
Units remaining unvested shall vest upon, and in the same proportion as, the
conversion of Subordinated Units.
The Company will recognize compensation expense in the future for the
Restricted Units, Unit Options and Transaction Grants described above, when
vesting becomes probable.
NOTE 11 - RETIREMENT PLAN
- -------------------------
Effective June 1, 1996, the Company's Board of Directors adopted a
nonqualified retirement plan (the "Plan") for certain officers of the Company.
Benefits under the Plan are based on salary at the time of adoption, vest over a
15 year period and are payable over a 15 year period commencing at age 60. The
Plan is unfunded.
Net pension expense for the years ended December 31, 1998 and 1997, is
comprised of the following components:
Year Ended
December 31,
-------------------------
1998 1997
----------- -----------
(in thousands)
Service cost - benefits earned during the period $ 97 $ 82
Interest on projected benefit obligation 74 60
Amortization of prior service cost 37 37
Unrecognized loss 3 -
----------- -----------
Net pension expense $ 211 $ 179
=========== ===========
F-18
<PAGE>
The following schedule reconciles the status of the Plan with amounts
reported in the Company's balance sheet at December 31, 1998 and 1997.
<TABLE>
<CAPTION>
December 31,
-----------------------
1998 1997
---------- ----------
(in thousands)
<S> <C> <C>
Actuarial present value of benefit obligations:
Vested benefits $ 1,108 $ 857
Nonvested benefits 172 184
---------- ----------
Accumulated benefit obligation 1,280 1,041
========== ==========
Projected benefit obligation for service rendered to date $ 1,280 $ 1,041
Plan assets at fair value - -
---------- ----------
Projected benefit obligation for service rendered to date 1,280 1,041
Unrecognized loss (211) (145)
Prior service cost not yet recognized in net periodic pension expense (582) (619)
---------- ----------
Net pension liability 487 277
Adjustment required to recognize minimum liability 582 619
---------- ----------
Accrued pension cost liability recognized in the balance sheet $ 1,069 $ 896
========== ==========
</TABLE>
The weighted-average discount rate used in determining the projected
benefit obligation was 6.5% and 7% for the years ended December 31, 1998 and
1997, respectively.
NOTE 12 - STOCK COMPENSATION PLANS
- ----------------------------------
Historically, the Company has used stock options as a long-term incentive
for its employees, officers and directors under various stock option plans. The
exercise price of options granted to employees is equal to or greater than the
market price of the underlying stock on the date of grant. Accordingly,
consistent with the provisions of Accounting Principles Board Opinion No. 25,
Accounting for Stock Issued to Employees ("APB 25"), no compensation expense has
been recognized in the accompanying financial statements.
During 1996, the Company's shareholders approved the Company's 1996 Stock
Incentive Plan, under which a maximum of 1.5 million shares of Common Stock were
reserved for issuance. The Company also has options outstanding under its 1991
and 1992 plans, under which a maximum of 2.0 million shares of Common Stock were
reserved for issuance. Generally, terms of the options provide for an exercise
price of not less than the market price of the Company's stock on the date of
the grant, a pro rata vesting period of two to four years and an exercise period
of five to ten years.
In addition, during 1996, the Company granted performance options to
purchase a total of 500,000 shares of Common Stock to two executive officers.
Terms of the options provide for an exercise price of $13.50, the market price
on the date of grant, and an exercise period of five years. The performance
options vest when the price of the Common Stock trades at or above $24 per share
for any 20 trading days in any 30 consecutive trading day period or upon a
change in control if certain conditions are met.
A summary of the status of the Company's stock options as of December 31,
1998, 1997, and 1996, and changes during the years ending on those dates are
presented below:
<TABLE>
<CAPTION>
1998 1997 1996
-------------------- -------------------- --------------------
Weighted- Weighted- Weighted-
Average Average Average
Shares Exercise Shares Exercise Shares Exercise
Fixed Options (000) Price (000) Price (000) Price
- ----------------------------------- --------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning of year 2,614 $ 9.50 2,435 $ 8.56 1,728 $ 6.40
Granted 333 $ 16.62 384 $ 14.33 1,060 $ 11.34
Exercised (179) $ 6.71 (163) $ 6.80 (285) $ 6.26
Forfeited (19) $ 11.36 (42) $ 9.82 (68) $ 6.63
--------- --------- ---------
Outstanding at end of year 2,749 $ 10.53 2,614 $ 9.50 2,435 $ 8.56
========= ========= =========
Options exercisable at year-end 1,646 $ 8.53 1,494 $ 7.24 1,289 $ 6.78
========= ========= =========
Weighted-average fair value of
options granted during the year $ 4.93 $ 4.53 $ 3.19
</TABLE>
F-19
<PAGE>
In October 1995, the Financial Accounting Standards Board issued SFAS
No. 123, Accounting for Stock-Based Compensation. SFAS No. 123 establishes
financial accounting and reporting standards for stock-based employee
compensation. The pronouncement defines a fair value based method of accounting
for an employee stock option or similar equity instrument. SFAS No. 123 also
allows an entity to continue to measure compensation cost for those instruments
using the intrinsic value-based method of accounting prescribed by APB 25. The
Company has elected to follow APB 25 and related Interpretations in accounting
for its employee stock options because, as discussed below, the alternative fair
value accounting provided for under SFAS No. 123 requires the use of option
valuation models that were not developed for use in valuing employee stock
options. Under APB 25, because the exercise price of the Company's employee
stock options equals the market price of the underlying stock on the date of
grant, no compensation expense has been recognized in the accompanying financial
statements. The Company will recognize compensation expense under APB 25 in the
future for the two performance options described above, if certain conditions
are met and such options vest.
Pro forma information regarding net income and EPS is required by SFAS
No. 123 and has been determined as if the Company had accounted for its employee
stock options under the fair value method as provided therein. The fair value
for the options was estimated at the date of grant using a Black-Scholes option
pricing model with the following weighted-average assumptions for grants in
1998, 1997 and 1996: risk-free interest rates of 5.6% for 1998, 6.1% for 1997
and 6.0% for 1996; a volatility factor of the expected market price of the
Company's common stock of .38 for 1998, .42 for 1997 and .36 for 1995; no
expected dividends; and weighted-average expected option lives of 2.7 years in
1998, 2.6 years in 1997 and 2.7 years in 1996.
The Black-Scholes option valuation model and other existing models were
developed for use in estimating the fair value of traded options that have no
vesting restrictions and are fully transferable. In addition, option valuation
models require the input of and are highly sensitive to subjective assumptions
including the expected stock price volatility. Because the Company's employee
stock options have characteristics significantly different from those of traded
options, and because changes in the subjective input assumptions can materially
affect the fair value estimate, in management's opinion, the existing models do
not provide a reliable single measure of the fair value of its employee stock
options.
For purposes of pro forma disclosures, the estimated fair value of the
options is amortized to expense over the options vesting period. Set forth below
is a summary of the Company's net income and EPS as reported and pro forma as if
the fair value based method of accounting defined in SFAS No. 123 had been
applied. The pro forma information is not meant to be representative of the
effects on reported net income for future years, because as provided by
SFAS 123, the effects of awards granted before December 31, 1994, are not
considered in the pro forma calculations.
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------------------------------------------------
1998 1997 1996
------------------------- ------------------------- -------------------------
As Pro As Pro As Pro
Reported Forma Reported Forma Reported Forma
------------ ------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
Net income/(loss) (in thousands) $(58,554) $(59,262) $ 14,259 $ 13,665 $ 16,548 $ 16,161
Basic EPS $ (3.77) $ (3.81) $ 0.85 $ 0.81 $ 1.01 $ 0.99
Diluted EPS $ (3.77) $ (3.81) $ 0.77 $ 0.74 $ 0.94 $ 0.92
</TABLE>
The following table summarizes information about stock options outstanding
at December 31, 1998:
<TABLE>
<CAPTION>
Weighted
Average Weighted Weighted
Number Remaining Average Number Average
Range of Outstanding Contractual Exercise Exercisable Exercise
Exercise Price at 12/31/98 Life Price at 12/31/98 Price
- ----------------------- ------------ ------------- ------------ ------------- ------------
(share amounts in thousands)
<S> <C> <C> <C> <C> <C>
$ 5.25 to $ 6.75 917 3.8 years $ 6.14 899 $ 6.13
$ 7.50 to $ 7.81 445 4.3 years $ 7.65 369 $ 7.63
$10.50 to $ 15.63 1,282 3.1 years $ 13.96 273 $ 13.53
$19.19 to $ 19.19 105 4.4 years $ 19.19 105 $ 19.19
--------- ---------
$ 5.25 to $ 19.19 2,749 3.6 years $ 10.53 1,646 $ 8.53
========= =========
</TABLE>
During 1998, 1997 and 1996, pursuant to Board of Directors' resolutions,
the Company contributed approximately 28,000, 21,000 and 18,000 shares,
respectively, of Common Stock at weighted average prices of $16.21, $15.22 and
$11.35 per share, respectively, on behalf of participants in the Company's
401(k) Savings Plan, representing a matching contribution by the Company for 50%
of an employee's contribution.
F-20
<PAGE>
NOTE 13 - COMMITMENTS, CONTINGENCIES AND INDUSTRY CONCENTRATION
- ---------------------------------------------------------------
Commitments and Contingencies
Minimum commitments in connection with office space and office equipment
leased by the Company are: 1999 - $1.8 million; 2000 and 2001 - $1.7 million
annually; 2002 and 2003 - $1.6 million annually; thereafter - $4.1 million.
Rental payments made under the terms of similar arrangements totaled
approximately $1.3 million in 1998 and $1.1 million in 1997 and in 1996.
In connection with its crude oil marketing, PAA provides certain purchasers
and transporters with irrevocable standby letters of credit to secure PAA's
obligation for the purchase of crude oil (See Note 4). Generally, these letters
of credit are issued for up to seventy day periods and are terminated upon
completion of each transaction. At December 31, 1998, PAA had outstanding
letters of credit of approximately $62 million. Such letters of credit are
secured by the crude oil inventory and accounts receivable of PAA (See Note 4).
The Company incurred costs associated with leased land, rights-of-way,
permits and regulatory fees of $.3 million during 1998. At December 31, 1998,
minimum future payments, net of sublease income, associated with these contracts
are approximately $.3 million for the following year. Generally these contracts
extend beyond one year but can be canceled at any time should they not be
required for operations.
In order to receive electrical power service at certain remote locations,
the Company has entered into facilities contracts with several utility
companies. These facilities charges are calculated periodically based upon,
among other factors, actual electricity energy used. Minimum future payments for
these contracts at December 31, 1998, are approximately $760,000 annually for
each of the next five years.
Under the amended terms of an asset purchase agreement between the Company
and Chevron, commencing with the year beginning January 1, 2000, and each year
thereafter, the Company is required to plug and abandon 20% of the then
remaining inactive wells, which currently aggregate approximately 225. To the
extent the Company elects not to plug and abandon the number of required wells,
the Company is required to escrow an amount equal to the greater of $25,000 per
well or the actual average plugging cost per well in order to provide for the
future plugging and abandonment of such wells. In addition, the Company is
required to expend a minimum of $600,000 per year in each of the ten years
beginning January 1, 1996, and $300,000 per year in each of the succeeding five
years to remediate oil contaminated soil from existing well sites, provided
there are remaining sites to be remediated. In the event the Company does not
expend the required amounts during a calendar year, the Company is required to
contribute an amount equal to 125% of the actual shortfall to an escrow account.
The Company may withdraw amounts from such escrow account to the extent it
expends excess amounts in a future year. As of December 31, 1998, the Company
has not been required to make contributions to an escrow account.
Although the Company obtained environmental studies on its properties in
California, the Sunniland Trend and the Illinois Basin and the Company believes
that such properties have been operated in accordance with standard oil field
practices, certain of the fields have been in operation for more than 90 years,
and current or future local, state and federal environmental laws and
regulations may require substantial expenditures to comply with such rules and
regulations. In connection with the purchase of certain of its California
Properties, the Company received a limited indemnity from Chevron for certain
conditions if they violate applicable local, state and federal environmental
laws and regulations in effect on the date of such agreement. While the Company
believes that it does not have any material obligations for operations conducted
prior to the Company's acquisition of the properties from Chevron, other than
its obligation to plug existing wells and those normally associated with
customary oil field operations of similarly situated properties, there can be no
assurance that current or future local, state or federal rules and regulations
will not require it to spend material amounts to comply with such rules and
regulations or that any portion of such amounts will be recoverable under the
Chevron indemnity.
Consistent with normal industry practices, substantially all of the
Company's oil and natural gas leases require that, upon termination of economic
production, the working interest owners plug and abandon non-producing
wellbores, remove tanks, production equipment and flow lines and restore the
wellsite. The Company has estimated that the costs to perform these tasks is
approximately $12.8 million, net of salvage value and other considerations. Such
estimated costs are amortized to expense through the unit-of-production method
as a component of accumulated depreciation, depletion and amortization ("DD&A").
Results from operations for 1998, 1997 and 1996 include $0.8 million, $0.6
million and $0.8 million, respectively, of expense associated with these
estimated future costs. For valuation and realization purposes of the affected
oil and natural gas properties, these estimated future costs are also deducted
from estimated future gross revenues to arrive at the estimated future net
revenues and the Standardized Measure disclosed in Note 18.
F-21
<PAGE>
As is common within the industry, the Company has entered into various
commitments and operating agreements related to the exploration and development
of and production from certain proved oil and natural gas properties and the
marketing, transportation, terminalling and storage of crude oil. It is
management's belief that such commitments will be met without a material adverse
effect on the Company's financial position, results of operations or cash flows.
In March 1999, PAA signed a definitive agreement to acquire Scurlock
Permian LLC and certain other pipeline assets (See Note 21).
Industry Concentration
Financial instruments which potentially subject the Company to
concentrations of credit risk consist principally of trade receivables. The
Company's accounts receivable are primarily from purchasers of oil and natural
gas products. This industry concentration has the potential to impact the
Company's overall exposure to credit risk, either positively or negatively, in
that the customers may be similarly affected by changes in economic, industry or
other conditions. The Company generally requires letters of credit for
receivables from customers which are not considered investment grade, unless the
credit risk can otherwise be mitigated.
There are a limited number of alternative methods of transportation for the
Company's production. Substantially all of the Company's California crude oil
and natural gas production and its Sunniland Trend and Illinois Basin oil
production is transported by pipelines, trucks and barges owned by third
parties. The inability or unwillingness of these parties to provide
transportation services to the Company for a reasonable fee could result in the
Company having to find transportation alternatives, increased transportation
costs to the Company or involuntary curtailment of a significant portion of its
crude oil and natural gas production which could have a negative impact on
future results of operations or cash flows.
NOTE 14 - LITIGATION
- --------------------
During 1996, the Company settled two lawsuits filed in 1992 and 1993,
relating to activities in 1991 and 1992, against certain of its officers and
directors for a cash payment of approximately $6.3 million. Approximately $4.1
million of such amount was paid by the Company's insurance carrier and $2.2
million was paid by the Company. Taking into account prior costs incurred by the
Company to defend these suits, and for which the Company agreed to relinquish
its claims for reimbursement against its insurance company, this settlement
resulted in a charge to 1996 first quarter earnings of $4 million.
On July 9, 1987, Exxon Corporation ("Exxon") filed an interpleader action
in the United States District Court for the Middle District of Florida, Exxon
Corporation v. E. W. Adams, et al., Case Number 87-976-CIV-T-23-B. This action
was filed by Exxon to interplead royalty funds as a result of a title
controversy between certain mineral owners in a field in Florida. One group of
mineral owners, John W. Hughes, et al. (the "Hughes Group"), filed a
counterclaim against Exxon alleging fraud, conspiracy, conversion of funds,
declaratory relief, federal and Florida RICO, breach of contract and accounting,
as well as challenging the validity of certain oil and natural gas leases owned
by Exxon, and seeking exemplary and treble damages. In March 1993, but effective
November 1, 1992, Calumet Florida, Inc. ("Calumet"), a wholly owned subsidiary
of the Company, acquired all of Exxon's leases in the field affected by this
lawsuit. In order to address those counterclaims challenging the validity of
certain oil and natural gas leases, which constitute approximately 10% of the
land underlying this unitized field, Calumet filed a motion to join Exxon as
plaintiff in the subject lawsuit, which was granted July 29, 1994. In August
1994, the Hughes Group amended its counterclaim to add Calumet as a counter-
defendant. Exxon and Calumet filed a motion to dismiss the counterclaims. On
March 22, 1996, the Court granted Exxon's and Calumet's motion to dismiss the
counterclaims alleging fraud, conspiracy, and federal and Florida RICO
violations and challenging the validity of certain of the Company's oil and
natural gas leases but denied such motion as to the counterclaim alleging
conversion of funds. 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 disputes over
certain title issues. Motions have been filed requesting the Court to rule on
the disputes, but no hearing date has been set. The Company does not believe
that the disputes will adversely affect the settlement reached between the
Company and the defendants.
The Company, in the ordinary course of business, is a claimant and/or a
defendant in various other legal proceedings in which its exposure, individually
and in the aggregate, is not considered material to the consolidated financial
statements.
F-22
<PAGE>
NOTE 15 - MAJOR CUSTOMERS
- -------------------------
Sales to Sempra Energy Trading Corporation ("Sempra") (formerly AIG
Trading Corporation) and Koch Oil Company ("Koch") accounted for 27% and 15%,
respectively, of the Company's total revenue (exclusive of interest and other
income) during 1998. Customers accounting for more than 10% of total revenue
for 1997 and 1996 were as follows: 1997 -- Koch -27% and Sempra - 11%, 1996 --
Koch-16% and Basis Petroleum, Inc. (formerly Phibro Energy USA, Inc.) - 11%. No
other single customer accounted for as much as 10% of total sales during 1998,
1997 or 1996. Additionally during 1998, Tosco Refining Company and Scurlock
Permian LLC accounted for approximately 50% and 17%, respectively, of the
Company's oil and gas sales.
NOTE 16 - FINANCIAL INSTRUMENTS
- -------------------------------
Derivatives
The Company has only limited involvement with derivative financial
instruments, as defined in SFAS No. 119, Disclosure About Derivative Financial
Instruments and Fair Value of Financial Instruments and does not use them for
speculative trading purposes. The Company's principle objective is to hedge
exposure to price volatility on crude oil and natural gas. These arrangements
expose the Company to credit risk (as to counterparties) and to risk of adverse
price movements in certain cases where the Company's production is less than
expected. Substantially all derivatives are either exchange traded or with major
financial institutions and the risk of loss is considered remote.
The Company has entered into various arrangements to fix the NYMEX crude
oil spot price ("NYMEX Crude Oil Price") for a significant portion of its crude
oil production. On December 31, 1998, these arrangements provided for a NYMEX
Crude Oil Price for 9,000 barrels per day from January 1, 1999, through
December 31, 1999, at approximately $18.25 per barrel. Since December 31, 1998,
the Company has entered into additional arrangements which provide for a NYMEX
Crude Oil Price for 2,000 barrels per day from January 1, 2000, through
December 31, 2000, at $15.30 per barrel. Location and quality differentials
attributable to the Company's properties are not included in the foregoing
prices. The agreements provide for monthly settlement based on the differential
between the agreement price and the actual NYMEX Crude Oil Price. Gains or
losses are recognized in the month of related production and are included in oil
and natural gas sales.
In addition, the Company has entered into ten year swap agreements with
various financial institutions to hedge the interest rate on an aggregate of
$200 million of bank debt. Approximately $175 million of such debt relates to
the Term Loan Facility of PAA and fixes the LIBOR portion of the interest rate
on such loan at approximately 5.24%. The remaining $25 million swap locks in
LIBOR at approximately 5.9%.
Fair Value of Financial Instruments
The following disclosure of the estimated fair value of financial
instruments is made in accordance with the requirements of SFAS No. 107,
Disclosures About Fair Value of Financial Instruments. The estimated fair value
amounts have been determined by the Company using available market information
and valuation methodologies described below. Considerable judgement is required
in interpreting market data to develop the estimates of fair value. The use of
different market assumptions or valuation methodologies may have a material
effect on the estimated fair value amounts.
The carrying values of items comprising current assets and current
liabilities approximate fair values due to the short-term maturities of these
instruments. Crude oil futures contracts permit settlement by delivery of the
crude oil and, therefore, are not financial instruments, as defined.
F-23
<PAGE>
The carrying amounts and fair values of the Company's other financial
instruments are as follows:
<TABLE>
<CAPTION>
December 31,
----------------------------------------------------------
1998 1997
---------------------------- ----------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
------------- ------------- ------------- -------------
(in thousands)
<S> <C> <C> <C> <C>
Long Term Debt:
Bank debt $ 227,000 $ 227,000 $ 80,000 $ 80,000
Subordinated debt 202,427 202,000 202,661 214,750
Other long-term debt 2,556 2,556 3,067 3,067
Redeemable Preferred Stock 88,487 88,487 - -
Off Balance Sheet Financial Information:
Unrealized gain on crude oil swap agreements (1) - 16,870 - 7,246
Unrealized loss on interest rate swap agreements - (3,253) - -
</TABLE>
- --------------------
(1) These amounts represent the calculated difference between the NYMEX Crude
Oil Price and the hedge arrangements for future production of the
Company's properties as of December 31, 1998 and 1997. Such hedges, and
therefore the unrealized gains, have been included in estimated future
gross revenues to arrive at the estimated future net revenues and the
Standardized Measure disclosed in Note 18.
The carrying value of bank debt approximates its fair value as interest
rates are variable, based on prevailing market rates. The fair value of
subordinated debt was based on quoted market prices based on trades of
subordinated debt. Other long-term debt was valued by discounting the future
payments using the Company's incremental borrowing rate. The fair value of the
Redeemable Preferred Stock is estimated to be its liquidation value at
December 31, 1998. The fair value of the interest rate swap is based on the
termination value at December 31, 1998.
NOTE 17 - SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
- -----------------------------------------------------------
Selected cash payments and noncash activities were as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------
1998 1997 1996
---------- ----------- -----------
(in thousands)
<S> <C> <C> <C>
Cash paid for interest (net of amount capitalized) $ 34,546 $ 20,486 $ 16,309
========== =========== ===========
Noncash investing and financing activities:
Series D Preferred Stock Dividends $ 1,275 $ 163 $ -
========== =========== ===========
Series E Preferred Stock Dividends $ 3,487 $ - $ -
========== =========== ===========
Tax benefit from exercise of employee stock options $ 653 $ 513 $ -
========== =========== ===========
Detail of properties acquired for other than cash:
Fair value of acquired assets $ - $ 22,140 $ -
Debt issued and liabilities assumed - - -
Property exchanged - (1,619) -
Capital stock and warrants issued - (21,408) -
---------- ----------- -----------
Cash (received) paid $ - $ (887) $ -
========== =========== ===========
</TABLE>
F-24
<PAGE>
NOTE 18 - OIL AND NATURAL GAS ACTIVITIES
- -----------------------------------------
Costs Incurred
The Company's oil and natural gas acquisition, exploration, exploitation
and development activities are conducted in the United States. The following
table summarizes the costs incurred in connection therewith during the last
three years.
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------
1998 1997 1996
------------ ------------ -----------
(in thousands)
<S> <C> <C> <C>
Property acquisitions costs:
Unproved properties $ 6,266 $ 15,249 $ 728
Proved properties 3,851 28,182 3,087
Exploration costs 1,657 1,730 2,433
Exploitation and development costs 89,161 82,217 45,007
------------ ------------ -----------
$ 100,935 $ 127,378 $ 51,255
============ ============ ===========
</TABLE>
Capitalized Costs
The following table presents the aggregate capitalized costs subject to
amortization relating to the Company's oil and natural gas acquisition,
exploration, exploitation and development activities, and the aggregate related
DD&A. Under full cost accounting rules as prescribed by the SEC, unamortized
costs of proved oil and natural gas properties are subject to a ceiling, which
limits such costs to the Standardized Measure (as described below). At
December 31, 1998, the capitalized costs of the Company's proved oil and natural
gas properties exceeded the Standardized Measure and the Company recorded a non-
cash, after tax charge to expense of $109.0 million ($173.9 million pre-tax).
Year Ended December 31,
-----------------------------
1998 1997
------------- --------------
(in thousands)
Proved properties $ 596,203 $ 498,038
Accumulated DD&A (369,260) (171,162)
------------- --------------
$ 226,943 $ 326,876
============= ==============
The DD&A rate per equivalent unit of production excluding the writedown in
1998 was $3.00, $2.83 and $3.00 for the years ended December 31, 1998, 1997 and
1996, respectively.
Costs Not Subject to Amortization
The following table summarizes the categories of costs which comprise the
amount of unproved properties not subject to amortization.
December 31,
-----------------------------
1998 1997
------------- --------------
(in thousands)
Acquisition costs $ 47,657 $ 41,652
Exploration costs 2,467 2,573
Capitalized interest 4,421 7,799
------------- --------------
$ 54,545 $ 52,024
============= ==============
Unproved property costs not subject to amortization consist mainly of
acquisition and lease costs and seismic data related to unproved areas. The
Company will continue to evaluate these properties over the lease terms;
however, the timing of the ultimate evaluation and disposition of a significant
portion of the properties has not been determined. Costs associated with seismic
data and all other costs will become subject to amortization as the prospects to
which they relate are evaluated. Approximately 20%, 35% and 5% of the balance in
unproved properties at December 31, 1998, related to additions made in 1998,
1997 and 1996, respectively.
During 1998, 1997 and 1996, the Company capitalized $3.7 million, $3.3
million and $3.6 million, respectively, of interest related to the costs of
unproved properties in the process of development.
F-25
<PAGE>
Supplemental Reserve Information (Unaudited)
The following information summarizes the Company's net proved reserves of
oil (including condensate and natural gas liquids) and natural gas and the
present values thereof for the three years ended December 31, 1998. The
following reserve information is based upon reports of the independent petroleum
consulting firms of H.J. Gruy and Company, Netherland Sewell & Associates, Inc.,
Ryder Scott Company and System Technology Associates, Inc. The estimates are in
accordance with regulations prescribed by the Securities and Exchange Commission
("SEC").
In management's opinion, the reserve estimates presented herein, in
accordance with generally accepted engineering and evaluation principles
consistently applied, are believed to be reasonable. However, there are numerous
uncertainties inherent in estimating quantities and values of proved reserves
and in projecting future rates of production and timing of development
expenditures, including many factors beyond the control of the Company. Reserve
engineering is a subjective process of estimating the recovery from underground
accumulations of oil and natural gas that cannot be measured in an exact manner,
and the accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Because all reserve estimates are to some degree speculative, the quantities of
oil and natural gas that are ultimately recovered, production and operating
costs, the amount and timing of future development expenditures and future oil
and natural gas sales prices may all differ from those assumed in these
estimates. In addition, different reserve engineers may make different estimates
of reserve quantities and cash flows based upon the same available data.
Therefore, the Standardized Measure shown below represents estimates only and
should not be construed as the current market value of the estimated oil and
natural gas reserves attributable to the Company's properties. In this regard,
the information set forth in the following tables includes revisions of reserve
estimates attributable to proved properties included in the preceding year's
estimates. Such revisions reflect additional information from subsequent
exploitation and development activities, production history of the properties
involved and any adjustments in the projected economic life of such properties
resulting from changes in product prices.
Decreases in the prices of oil and natural gas have had, and could have in
the future, an adverse effect on the carrying value of the Company's proved
reserves and the Company's revenues, profitability and cash flow. Almost all of
the Company's reserve base (approximately 90% of year-end 1998 reserve volumes)
is comprised of long-life oil properties that are sensitive to crude oil price
volatility. The crude oil price at December 31, 1998, upon which proved reserve
volumes, the estimated present value (discounted at 10%) of future net revenue
from the Company's proved oil and natural gas reserves (the "Present Value of
Proved Reserves") and the Standardized Measure as of such date were based, was
$12.05 per barrel. Such price was the lowest year-end price since oil was
deregulated in 1980 and was approximately 34% below the price used in preparing
reserve estimates at the end of 1997.
Estimated Quantities of Oil and Natural Gas Reserves (Unaudited)
The following table sets forth certain data pertaining to the Company's
proved and proved developed reserves for the three years ended December 31,
1998.
<TABLE>
<CAPTION>
As of or for the Year Ended December 31,
-----------------------------------------------------------------------------
1998 1997 1996
------------------------- ------------------------- ------------------------
Oil Gas Oil Gas Oil Gas
(Bbl) (Mcf) (Bbl) (Mcf) (Bbl) (Mcf)
------------ ------------ ------------ ----------- ----------- -----------
(in thousands)
<S> <C> <C> <C> <C> <C> <C>
Proved Reserves
Beginning balance 151,627 60,350 115,996 37,273 94,408 43,110
Revision of previous estimates (46,282) 2,925 (16,091) 3,805 19,424 6,641
Extensions, discoveries, improved
recovery and other additions 14,729 29,306 17,884 8,126 8,179 1,294
Sale of reserves in-place - (2,799) (26) (547) (5) (12,491)
Purchase of reserves in-place 7,709 - 40,764 14,566 45 862
Production (7,575) (3,001) (6,900) (2,873) (6,055) (2,143)
------------ ------------ ------------ ----------- ----------- -----------
Ending balance 120,208 86,781 151,627 60,350 115,996 37,273
============ ============ ============ =========== =========== ===========
Proved Developed Reserves
Beginning balance 99,193 38,233 86,515 25,629 67,266 29,397
============ ============ ============ =========== =========== ===========
Ending balance 73,264 58,445 99,193 38,233 86,515 25,629
============ ============ ============ =========== =========== ===========
</TABLE>
F-26
<PAGE>
Standardized Measure of Discounted Future Net Cash Flows (Unaudited)
The Standardized Measure of discounted future net cash flows relating to
proved oil and natural gas reserves is presented below:
<TABLE>
<CAPTION>
December 31,
----------------------------------------------
1998 1997 1996
------------- ------------- -------------
(in thousands)
<S> <C> <C> <C>
Future cash inflows $ 1,102,863 $ 2,237,876 $ 2,681,007
Future development costs (117,924) (157,877) (111,785)
Future production expense (546,091) (1,019,254) (977,551)
Future income tax expense - (261,130) (437,654)
------------- ------------- -------------
Future net cash flows 438,848 799,615 1,154,017
Discounted at 10% per year (211,905) (387,792) (575,436)
------------- ------------- -------------
Standardized measure of
discounted future net cash flows $ 226,943 $ 411,823 $ 578,581
============= ============= =============
</TABLE>
The Standardized Measure of discounted future net cash flows (discounted at
10%) from production of proved reserves was developed as follows:
1. An estimate was made of the quantity of proved reserves and the future
periods in which they are expected to be produced based on year-end
economic conditions.
2. In accordance with SEC guidelines, the engineers' estimates of future
net revenues from the Company's proved properties and the present value
thereof are made using oil and natural gas sales prices in effect as of
the dates of such estimates and are held constant throughout the life of
the properties, except where such guidelines permit alternate treatment,
including the use of fixed and determinable contractual price
escalations. The crude oil price received by the Company at December 31,
1998, is based on the NYMEX Crude Oil Price of $12.05 per barrel with
variations therefrom based on location and grade of crude oil. The
Company has entered into various fixed price and floating price collar
arrangements to fix or limit the NYMEX Crude Oil Price for a significant
portion of its crude oil production. Arrangements in effect at
December 31, 1998, are reflected in the reserve reports through the term
of the arrangements (See Note 16). The overall average prices used in
the reserve reports as of December 31, 1998, were $7.96 per barrel of
crude oil, condensate and natural gas liquids and $1.68 per Mcf of
natural gas.
3. The future gross revenue streams were reduced by estimated future
operating costs (including production and ad valorem taxes) and future
development and abandonment costs, all of which were based on current
costs.
4. The reports reflect the Present Value of Proved Reserves to be $226.9
million, $511.0 million and $764.8 million at December 31, 1998, 1997
and 1996, respectively. SFAS No. 69 requires the Company to further
reduce these estimates by an amount equal to the present value of
estimated income taxes which might be payable by the Company in future
years to arrive at the Standardized Measure. Future income taxes were
calculated by applying the statutory federal income tax rate to pretax
future net cash flows, net of the tax basis of the properties involved
and utilization of available tax carryforwards. A large portion of the
Company's reserve base (approximately 90% of year-end 1998 reserve
volumes) is comprised of long-life oil properties that are sensitive to
crude oil price volatility. By comparison, using a NYMEX Crude Oil Price
of $18.34 per barrel, results in a Present Value of Proved Reserves of
$705 million and estimated net proved reserves of 219 million barrels of
oil equivalent. Such information is based upon reserve reports prepared
by independent petroleum engineers, in accordance with the rules and
regulations of the SEC, using the same crude oil price used in preparing
year-end 1997 reserve information.
F-27
<PAGE>
The principal sources of changes in the Standardized Measure of future net
cash flows for the three years ended December 31, 1998, are as follows:
<TABLE>
<CAPTION>
Year End December 31,
-------------------------------------------
1998 1997 1996
------------- ------------- -------------
(in thousands)
<S> <C> <C> <C>
Balance, beginning of year $ 411,823 $ 578,581 $ 304,841
Sales, net of production expenses (51,927) (63,917) (58,866)
Net change in sales and transfer prices, net of production expenses (288,320) (359,138) 275,200
Changes in estimated future development costs 42,858 9,927 (5,188)
Extensions, discoveries and improved recovery, net of costs 21,095 84,676 50,013
Previously estimated development costs incurred during the year 25,501 23,449 19,662
Purchase of reserves in-place 14,173 74,278 2,253
Sales of reserves in-place (1,151) (1,501) (3,357)
Revision of quantity estimates (91,942) (57,597) 145,815
Accretion of discount 51,099 76,477 36,678
Net change in income taxes 99,170 87,024 (124,254)
Changes in estimated timing of production and other (5,436) (40,436) (64,216)
------------- ------------- -------------
Balance, end of year $ 226,943 $ 411,823 $ 578,581
============= ============= =============
</TABLE>
NOTE 19 - QUARTERLY FINANCIAL DATA (UNAUDITED)
- ----------------------------------------------
The following table shows summary financial data for 1998 and 1997.
<TABLE>
<CAPTION>
Quarter Ended
-------------------------------------------------------------------------
March 31, June 30, September 30, December 31,
-------------- -------------- ----------------- ----------------
(in thousands, except per share data)
1998
<S> <C> <C> <C> <C>
Revenues $ 193,572 $ 189,441 $ 393,719 $ 456,545 (1)
Operating profits 17,534 18,323 27,111 28,154 (1)
Net income 1,431 1,418 3,625 (65,028)
Basic EPS 0.07 0.07 0.11 (4.00)
Diluted EPS 0.06 0.06 0.10 (4.00)
1997
Revenues $ 207,132 $ 188,592 $ 220,660 $ 245,860
Operating profits 18,609 18,666 18,567 20,874
Net income 3,891 3,252 2,759 4,357
Basic EPS 0.24 0.20 0.17 0.25
Diluted EPS 0.22 0.18 0.15 0.23
</TABLE>
- ------------------
(1) Excludes the net gain of $60.8 million recorded upon the formation of PAA.
NOTE 20 - OPERATING SEGMENTS
- ----------------------------
The Company's operations consist of two operating segments: (1) Upstream
Operations - engages in the acquisition, exploitation, development, exploration
and production of crude oil and natural gas and (2) Midstream Operations -
engages in crude oil gathering, marketing, terminalling, storage and
transportation. The accounting policies of the segments are the same as those
described in the summary of significant accounting policies (See Note 1). The
Company evaluates segment performance based on gross margin, gross profit and
income before income taxes and extraordinary items.
F-28
<PAGE>
The following schedule summarizes certain segment information.
<TABLE>
<CAPTION>
(In thousands) Upstream Midstream Total
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
1998
Revenues:
External Customers $ 102,754 $ 1,129,689 $ 1,232,443
Intersegment (a) - 119 119
Interest income 250 584 834
-------------- ------------- -------------
Total revenues of reportable segments $ 103,004 $ 1,130,392 $ 1,233,396
============== ============= =============
Segment gross margin (b)(d) $ 51,927 $ 38,361 $ 90,288
Segment gross profit (c)(d) 46,446 33,064 79,510
Segment income/(loss) before income taxes
and extraordinary item (d) (175,926) 15,646 (160,280)
Interest expense 23,099 12,631 35,730
Depreciation, depletion and amortization 199,523 5,371 204,894
Income tax expense (benefit) (47,283) 4,563 (42,720)
Capital expenditures 100,935 405,508 506,443
Assets 364,059 610,208 974,267
- ------------------------------------------------------------------------------------------------------------
1997
Revenues:
External Customers $ 109,403 $ 752,522 $ 861,925
Intersegment (a) - - -
Interest income 181 138 319
-------------- ------------- -------------
Total revenues of reportable segments $ 109,584 $ 752,660 $ 862,244
============== ============= =============
Segment gross margin (b) $ 63,917 $ 12,480 $ 76,397
Segment gross profit (c) 59,106 8,951 68,057
Segment income before income taxes and
extraordinary item 19,178 3,408 22,586
Interest expense 17,496 4,516 22,012
Depreciation, depletion and amortization 22,613 1,165 23,778
Income tax expense (benefit) 7,059 1,268 8,327
Capital expenditures 127,378 5,381 132,759
Assets 407,200 149,619 556,819
- ------------------------------------------------------------------------------------------------------------
1996
Revenues:
External Customers $ 97,601 $ 531,698 $ 629,299
Intersegment (a) - - -
Interest income 219 90 309
-------------- ------------- -------------
Total revenues of reportable segments $ 97,820 $ 531,788 $ 629,608
============== ============= =============
Segment gross margin (b) $ 58,866 $ 9,531 $ 68,397
Segment gross profit (c) 54,111 6,557 60,668
Segment income before income taxes and
extraordinary item 15,806 1,948 17,754
Interest expense 13,727 3,559 17,286
Depreciation, depletion and amortization 20,797 1,140 21,937
Income tax expense (benefit) (4,624) 726 (3,898)
Capital expenditures 51,134 2,941 54,075
Assets 307,692 122,557 430,249
- ------------------------------------------------------------------------------------------------------------
</TABLE>
(a) Intersegment revenues and transfers were conducted on an arm's-length
basis.
(b) Gross margin is calculated as operating revenues less operating expenses.
(c) Gross profit is calculated as operating revenues less operating expenses
and general and administrative expenses.
(d) Differences between segment totals and Company totals represent the net
gain of $60.8 million recorded upon the formation of PAA, which was not
allocated to the segments.
F-29
<PAGE>
The following schedule reconciles segment revenues to amounts reported in
the Company's financial statements:
<TABLE>
<CAPTION>
For the Year Ended December 31,
------------------------------------------
1998 1997 1996
------------- ----------- -----------
<S> <C> <C> <C>
Revenues of reportable segments $ 1,233,396 $ 862,244 $ 629,608
Intersegment (119) - -
Net gain recorded upon the formation of PAA
not allocated to reportable segments 60,815 - -
------------- ----------- -----------
Total company revenues $ 1,294,092 862,244 629,608
============= =========== ===========
</TABLE>
NOTE 21 - SUBSEQUENT EVENT
- ---------------------------
On March 17, 1999, PAA signed a definitive agreement with Marathon Ashland
Petroleum LLC to acquire Scurlock Permian LLC and certain other pipeline assets.
The cash purchase price for the acquisition is approximately $138 million, plus
associated closing and financing costs. The purchase price is subject to
adjustment at closing for working capital on April 1, 1999, the effective date
of the acquisition. Closing of the transaction is subject to regulatory review
and approval, consents from third parties, and customary due diligence. Subject
to satisfaction of the foregoing conditions, the transaction is expected to
close in the second quarter of 1999. PAA has received a financing commitment
from one of its existing lenders, which in addition to other financial resources
currently available to PAA, will provide the funds necessary to complete the
transaction. The definitive agreement provides that if either party fails to
perform its obligations thereunder through no fault of the other party, such
defaulting party shall pay the nondefaulting party $7.5 million as liquidated
damages.
Scurlock Permian LLC, a wholly owned subsidiary of Marathon Ashland
Petroleum LLC, is engaged in crude oil transportation, trading and marketing,
operating in 14 states with more than 2,400 miles of active pipelines, numerous
storage terminals and a fleet of more than 225 trucks. Its largest asset is an
800-mile pipeline and gathering system located in the Spraberry Trend in West
Texas that extends into Andrews, Glasscock, Howard, Martin, Midland, Regan,
Upton and Irion Counties, Texas. The assets to be acquired also include
approximately one million barrels of crude oil used for linefill requirements.
NOTE 22 - CONSOLIDATING FINANCIAL STATEMENTS
- --------------------------------------------
On September 17, 1999, the Company announced that it agreed to sell $75
million principal amount of senior subordinated notes due 2006, Series E (the
"Series E Notes"). Such notes will bear a stated coupon rate of 10.25%, but will
be issued at approximately 101% of par, for a yield-to-worst of 9.97%. The
stated coupon rate of interest and maturity date will be the same as those of
the Company's existing $200 million principal amount of senior subordinated
notes. Closing is expected to occur on September 22, 1999. Net proceeds to the
Company, after costs of the transaction, will be approximately $74.6 million,
and will be used to reduce the outstanding balance on the Revolving Credit
Facility. The Series E Notes will be issued pursuant to a Rule 144A private
placement.
The Series E Notes will be unsecured senior subordinated obligations of the
Company and will be subordinated in right of payment to all existing and future
senior indebtedness of the Company. All of the Company's subsidiaries engaged in
its upstream business segment will initially guarantee payment under the Series
E Notes on a full, unconditional, joint and several basis. The Series E Notes
will not be guaranteed by PAA or any of the Company's other midstream
subsidiaries.
The following financial information presents consolidating financial
statements which include:
. the parent company only ("Parent");
. the guarantor subsidiaries on a combined basis ("Guarantor
Subsidiaries");
. the nonguarantor subsidiaries on a combined basis ("Nonguarantor
Subsidiaries");
. elimination entries necessary to consolidate the Parent, the Guarantor
Subsidiaries and the Nonguarantor Subsidiaries; and
. the Company on a consolidated basis.
F-30
<PAGE>
<TABLE>
<CAPTION>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET (in thousands)
DECEMBER 31, 1998
GUARANTOR NONGUARANTOR INTERCOMPANY
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
-------- ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 142 $ 194 $ 6,408 $ (200) $ 6,544
Accounts receivable 276 8,549 120,050 - 128,875
Inventory - 4,809 37,711 - 42,520
Prepaid expenses and other 561 361 605 - 1,527
--------- --------- -------- --------- ----------
Total current assets 979 13,913 164,774 (200) 179,466
--------- --------- -------- --------- ----------
PROPERTY AND EQUIPMENT 234,127 424,646 378,835 - 1,037,608
Less allowance for depreciation,
depletion and amortization (228,579) (91,118) (799) (55,386) (375,882)
--------- --------- -------- --------- ----------
5,548 333,528 378,036 (55,386) 661,726
--------- --------- -------- --------- ----------
INVESTMENTS IN SUBSIDIARIES AND
INTERCOMPANY ADVANCES 246,581 (179,716) (2,847) (64,018) -
OTHER ASSETS 47,391 8,177 77,507 - 133,075
--------- --------- -------- --------- ----------
$ 300,499 $ 175,902 $617,470 $(119,604) $ 974,267
========= ========= ======== ========= ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and other current liabilities $ 18,425 $ 26,207 $138,714 $ (200) $ 183,146
Notes payable and other current obligations - 511 9,750 - 10,261
--------- --------- -------- --------- ----------
Total current liabilities 18,425 26,718 148,464 (200) 193,407
BANK DEBT 52,000 - - - 52,000
BANK DEBT OF A SUBSIDIARY - - 175,000 - 175,000
SUBORDINATED DEBT 202,427 - - - 202,427
OTHER LONG-TERM DEBT - 2,556 - - 2,556
OTHER LONG-TERM LIABILITIES 5,743 8,179 45 - 13,967
--------- --------- -------- --------- ----------
278,595 37,453 323,509 (200) 639,357
--------- --------- -------- --------- ----------
MINORITY INTEREST (70,037) - 243,498 - 173,461
--------- --------- -------- --------- ----------
SERIES E CUMULATIVE CONVERTIBLE
PREFERRED STOCK, STATED AT
LIQUIDATION PREFERENCE 88,487 - - - 88,487
--------- --------- -------- --------- ----------
NON-REDEEMABLE PREFERRED STOCK,
COMMON STOCK AND
OTHER STOCKHOLDERS' EQUITY
Series D Cumulative Convertible Preferred Stock 21,946 - - - 21,946
Common Stock 1,688 77 - (77) 1,688
Additional paid-in capital 124,679 3,954 38,727 (42,681) 124,679
Retained earnings (accumulated deficit) (144,859) 134,418 11,736 (76,646) (75,351)
--------- --------- -------- --------- ----------
3,454 138,449 50,463 (119,404) 72,962
--------- --------- -------- --------- ----------
$ 300,499 $ 175,902 $617,470 $(119,604) $ 974,267
========= ========= ======== ========= ==========
</TABLE>
F-31
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET (in thousands)
DECEMBER 31, 1997
<TABLE>
<CAPTION>
GUARANTOR NONGUARANTOR INTERCOMPANY
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
--------- ------------ ------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 4,911 $ 263 $ 1,452 $ (2,912) $ 3,714
Accounts receivable 879 3,849 94,869 - 99,597
Inventory 8 3,885 18,909 - 22,802
Prepaid expenses and other 233 362 72 - 667
--------- --------- -------- -------- ---------
Total current assets 6,031 8,359 115,302 (2,912) 126,780
--------- --------- -------- -------- ---------
PROPERTY AND EQUIPMENT 233,670 323,630 36,287 - 593,587
Less allowance for depreciation,
depletion and amortization (214,607) (45,253) (3,902) 83,483 (180,279)
--------- --------- -------- -------- ---------
19,063 278,377 32,385 83,483 413,308
--------- --------- -------- -------- ---------
INVESTMENTS IN SUBSIDIARIES AND
INTERCOMPANY ADVANCES 189,042 (118,815) (40,688) (29,539) -
OTHER ASSETS 17,356 8,124 1,792 (10,541) 16,731
--------- --------- -------- -------- ---------
$ 231,492 $ 176,045 $108,791 $ 40,491 $ 556,819
========= ========= ======== ======== =========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and other current liabilities $ 12,193 $ 18,665 $ 86,334 $ (2,912) $ 114,280
Notes payable and other current obligations - 511 18,000 - 18,511
--------- --------- -------- -------- ---------
Total current liabilities 12,193 19,176 104,334 (2,912) 132,791
BANK DEBT 80,000 - - - 80,000
SUBORDINATED DEBT 202,661 - - - 202,661
OTHER LONG-TERM DEBT - 3,067 - - 3,067
OTHER LONG-TERM LIABILITIES 2,949 11,395 1,304 (10,541) 5,107
--------- --------- -------- -------- ---------
297,803 33,638 105,638 (13,453) 423,626
--------- --------- -------- -------- ---------
NON-REDEEMABLE PREFERRED STOCK,
COMMON STOCK AND
OTHER STOCKHOLDERS' EQUITY
Series D Cumulative Convertible Preferred Stock 20,671 - - - 20,671
Common Stock 1,670 77 - (77) 1,670
Additional paid-in capital 122,887 6,102 359 (6,461) 122,887
Retained earnings (accumulated deficit) (211,539) 136,228 2,794 60,482 (12,035)
--------- --------- -------- -------- ---------
(66,311) 142,407 3,153 53,944 133,193
--------- --------- -------- -------- ---------
$ 231,492 $ 176,045 $108,791 $ 40,491 $ 556,819
========= ========= ======== ======== =========
</TABLE>
F-32
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENT OF OPERATIONS (in thousands)
YEAR ENDED DECEMBER 31, 1998
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C>
GUARANTOR NONGUARANTOR INTERCOMPANY
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
--------- ------------- ------------ ------------- ------------
REVENUES
Oil and natural gas sales $ - $102,634 $ - $ 120 $ 102,754
Marketing, transportation, storage and terminalling - - 1,129,809 (120) 1,129,689
Gain on formation of PAA 60,815 - - - 60,815
Interest and other income 40 76 718 - 834
----------- ----------- ----------- ----------- ------------
60,855 102,710 1,130,527 - 1,294,092
----------- ----------- ----------- ----------- ------------
EXPENSES
Production expenses - 50,827 - - 50,827
Marketing, transportation, storage and terminalling - - 1,091,328 - 1,091,328
General and administrative 1,536 3,946 5,296 - 10,778
Depreciation, depletion and amortization 5,521 20,127 5,372 - 31,020
Reduction in carrying cost of oil and natural gas
properties 9,267 25,738 - 138,869 173,874
Interest expense 11,389 11,710 12,631 - 35,730
----------- ----------- ----------- ------------ ------------
27,713 112,348 1,114,627 138,869 1,393,557
----------- ----------- ----------- ------------ ------------
Income (loss) before income taxes and minority interest 33,142 (9,638) 15,900 (138,869) (99,465)
Minority interest - - 1,809 - 1,809
----------- ----------- ----------- ------------ ------------
Income (loss) before income taxes 33,142 (9,638) 14,091 (138,869) (101,274)
Income tax expense (benefit)
Current (3,637) (3) 4,502 - 862
Deferred (20,855) (9,237) (13,490) - (43,582)
----------- ----------- ----------- ------------ ------------
NET INCOME (LOSS) 57,634 (398) 23,079 (138,869) (58,554)
Less: cumulative preferred stock dividends 4,762 - - - 4,762
----------- ----------- ----------- ------------ ------------
NET INCOME (LOSS) AVAILABLE TO
COMMON STOCKHOLDERS $ 52,872 $ (398) $ 23,079 $(138,869) $ (63,316)
=========== =========== =========== ============= =============
</TABLE>
F-33
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENT OF OPERATIONS (in thousands)
YEAR ENDED DECEMBER 31, 1997
<TABLE>
<CAPTION>
GUARANTOR NONGUARANTOR INTERCOMPANY
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
---------- ------------ ------------- ----------- -------------
<S> <C> <C> <C> <C> <C>
REVENUE
Oil and natural gas sales $ 867 $108,536 $ - $ - $109,403
Marketing, transportation, storage and terminalling - - 752,522 - 752,522
Interest and other income 90 91 138 - 319
----------- ----------- ----------- ----------- ------------
957 108,627 752,660 - 862,244
----------- ----------- ----------- ----------- ------------
EXPENSES
Production expenses 282 45,204 - - 45,486
Marketing, transportation, storage and terminalling - 9 740,033 - 740,042
General and administrative 1,294 3,517 3,529 - 8,340
Depreciation, depletion and amortization 5,887 16,741 1,150 - 23,778
Interest expense 10,111 7,384 4,517 - 22,012
----------- ----------- ----------- ----------- ------------
17,574 72,855 749,229 - 839,658
----------- ----------- ----------- ----------- ------------
Income (loss) before income taxes (16,617) 35,772 3,431 - 22,586
Income tax expense
Current (507) 792 67 - 352
Deferred 5,328 1,450 1,197 - 7,975
----------- ----------- ----------- ----------- ------------
NET INCOME (LOSS) (21,438) 33,530 2,167 - 14,259
Less: cumulative preferred stock dividends 163 - - - 163
----------- ----------- ----------- ----------- ------------
NET INCOME (LOSS) AVAILABLE TO
COMMON STOCKHOLDERS $(21,601) $ 33,530 $ 2,167 $ - $ 14,096
=========== =========== =========== ============ ============
</TABLE>
F-34
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENT OF OPERATIONS (in thousands)
YEAR ENDED DECEMBER 31, 1996
<TABLE>
<CAPTION>
GUARANTOR NONGUARANTOR INTERCOMPANY
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
--------- -------------- -------------- -------------- -------------
<S> <C> <C> <C> <C> <C>
REVENUES
Oil and natural gas sales $ 387 $97,214 $ - $ - $ 97,601
Marketing, transportation, storage and terminalling - - 531,698 - 531,698
Interest and other income 126 92 91 - 309
----------- ----------- ----------- ----------- ------------
513 97,306 531,789 - 629,608
----------- ----------- ----------- ----------- ------------
EXPENSES
Production expenses 177 38,558 - - 38,735
Marketing, transportation, storage and terminalling - 10 522,157 - 522,167
General and administrative 1,713 3,043 2,973 - 7,729
Depreciation, depletion and amortization 6,115 14,696 1,126 - 21,937
Interest expense 7,764 5,962 3,560 - 17,286
Litigation settlement 4,000 - - - 4,000
----------- ----------- ----------- ----------- ------------
19,769 62,269 529,816 - 611,854
----------- ----------- ----------- ----------- ------------
Income (loss) before income taxes and extraordinary item (19,256) 35,037 1,973 - 17,754
Income tax expense (benefit)
Deferred (8,618) 3,969 751 - (3,898)
----------- ----------- ----------- ----------- ------------
INCOME (LOSS) BEFORE EXTRAORDINARY ITEM (10,638) 31,068 1,222 - 21,652
EXTRAORDINARY ITEM:
Loss on early extinguishment of debt, net of tax benefit (5,104) - - - (5,104)
----------- ----------- ----------- ----------- ------------
NET INCOME (LOSS) $(15,742) $31,068 $ 1,222 $ $ 16,548
=========== =========== =========== =========== ============
</TABLE>
F-35
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (in thousands)
YEAR ENDED DECEMBER 31, 1998
<TABLE>
<CAPTION>
GUARANTOR NONGUARANTOR INTERCOMPANY
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ 57,634 $ (398) $ 23,079 $(138,869) $ (58,554)
Adjustments to reconcile net income to net cash provided
by (used in) operating activities:
Depreciation, depletion, and amortization 5,521 20,127 5,372 - 31,020
Reduction in carrying costs of oil and
natural gas properties 9,267 25,738 - 138,869 173,874
Non-cash gain (70,037) - - - (70,037)
Minority interest in income - - 1,809 - 1,809
Deferred income tax (20,855) (9,237) (13,490) - (43,582)
Other non-cash items 90 - - - 90
Change in assets and liabilities resulting from
operating activities:
Accounts receivable 603 (4,242) 28,591 - 24,952
Inventory 8 (924) (18,141) - (19,057)
Pipeline linefill - - (3,904) - (3,904)
Prepaids and other (328) 798 (1,338) - (868)
Accounts payable and other current liabilities 6,232 (10,782) 3,725 2,712 1,887
--------- --------- --------- --------- ---------
NET CASH FLOWS PROVIDED BY (USED IN)
OPERATING ACTIVITIES (11,865) 21,080 25,703 2,712 37,630
--------- --------- --------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Payment for acquisition of pipeline and related assets - - (394,026) - (394,026)
Payment for acquisition, exploration,
and development costs - (80,318) - - (80,318)
Payment for crude oil pipeline, gathering
and terminal assets - - (8,131) - (8,131)
Cash received from the sale of oil and
natural gas properties - 131 - - 131
Payment for additions to other property and other assets (510) (309) (259) - (1,078)
--------- --------- --------- --------- ---------
NET CASH USED IN INVESTING ACTIVITIES (510) (80,496) (402,416) - (483,422)
--------- --------- --------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Advances/investments with affiliates (54,060) 59,347 (5,287) - -
Proceeds from long-term debt 239,260 - 331,300 - 570,560
Proceeds from short-term debt - 31,750 - 31,750
Proceeds from sale of capital stock, options and warrants 828 - - - 828
Proceeds from issuance of preferred stock 85,000 - - - 85,000
Proceeds from issuance of common units - 244,690 - 244,690
Distributions upon formation 241,690 - (241,690) - -
Principal payments of long-term debt (384,260) - (39,300) - (423,560)
Principal payments of short-term debt - (40,000) - (40,000)
Capital contribution from Parent (113,700) - 113,700 - -
Dividend to Parent 3,557 - (3,557) - -
Debt issue costs incurred in connection with acquisition (6,138) - - - (6,138)
Debt issue and other costs incurred in connection
with public offering - - (9,937) - (9,937)
Other (4,571) - - - (4,571)
--------- --------- --------- --------- ---------
NET CASH PROVIDED BY FINANCING ACTIVITIES 7,606 59,347 381,669 - 448,622
--------- --------- --------- --------- ---------
Net increase (decrease) in cash and cash equivalents (4,769) (69) 4,956 2,712 2,830
Cash and cash equivalents, beginning of period 4,911 263 1,452 (2,912) 3,714
--------- --------- --------- --------- ---------
Cash and cash equivalents, end of period $ 142 $ 194 $ 6,408 $ (200) $ 6,544
========= ========= ========= ========= =========
</TABLE>
F-36
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (in thousands)
YEAR ENDED DECEMBER 31, 1997
<TABLE>
<CAPTION>
GUARANTOR NONGUARANTOR INTERCOMPANY
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ (21,438) $ 33,530 $ 2,167 $ - $ 14,259
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation, depletion, and amortization 5,887 16,741 1,150 - 23,778
Deferred income tax 5,328 1,450 1,197 - 7,975
Other non-cash items - 221 - - 221
Change in assets and liabilities resulting from
operating activities:
Accounts receivable 3,295 (3,451) (9,362) - (9,518)
Inventory (3) (1,786) (16,450) - (18,239)
Prepaids and other 10 209 (91) - 128
Accounts payable and other current liabilities (4,116) 6,051 9,343 425 11,703
--------- --------- ---------- -------- --------
NET CASH FLOWS PROVIDED BY (USED IN)
OPERATING ACTIVITIES (11,037) 52,965 (12,046) 425 30,307
--------- --------- ---------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Payment for acquisition, exploration,
and development costs (6,772) (98,874) - - (105,646)
Payment for crude oil pipeline, gathering and terminal assets - (923) - (923)
Cash received from the sale of oil and natural gas properties 2,667 - - - 2,667
Payment for additions to other property and other assets (430) (3,184) (118) - (3,732)
--------- --------- ---------- -------- --------
NET CASH USED IN INVESTING ACTIVITIES (4,535) (102,058) (1,041) - (107,634)
--------- --------- ---------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Advances/investments with affiliates (45,228) 49,638 (4,410) - -
Proceeds from long-term debt 266,905 - - - 266,905
Proceeds from short-term debt - - 39,000 - 39,000
Proceeds from sale of capital stock, options and warrants 1,104 - - - 1,104
Principal payments of long-term debt (206,500) (511) - - (207,011)
Principal payments of short-term debt - - (21,000) - (21,000)
Other (474) - - - (474)
--------- --------- ---------- -------- --------
NET CASH PROVIDED BY FINANCING ACTIVITIES 15,807 49,127 13,590 - 78,524
--------- --------- ---------- -------- --------
Net increase in cash and cash equivalents 235 34 503 425 1,197
Cash and cash equivalents, beginning of period 4,676 229 949 (3,337) 2,517
--------- --------- ---------- -------- --------
Cash and cash equivalents, end of period $ 4,911 $ 263 $ 1,452 $ (2,912) $ 3,714
========= ========= ========= ========= =========
</TABLE>
F-37
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (in thousands)
YEAR ENDED DECEMBER 31, 1996
<TABLE>
<CAPTION>
GUARANTOR NONGUARANTOR INTERCOMPANY
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ (15,742) $ 31,068 $ 1,222 $ - $ 16,548
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation, depletion, and amortization 6,115 14,696 1,126 - 21,937
Loss on early extinguishment of debt, net of tax 5,104 - - - 5,104
Deferred income tax (8,618) 3,969 751 - (3,898)
Other non-cash items 251 _ _ _ 251
Change in assets and liabilities resulting from
operating activities:
Accounts receivable (748) (1,138) (39,160) - (41,046)
Inventory 859 (743) 435 - 551
Prepaids and other (11) (92) 39 - (64)
Accounts payable and other current liabilities 4,956 (293) 36,160 (1,198) 39,625
--------- --------- --------- -------- --------
NET CASH FLOWS PROVIDED BY (USED IN)
OPERATING ACTIVITIES (7,834) 47,467 573 (1,198) 39,008
--------- --------- --------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Payment for acquisition, exploration,
and development costs 1,688 (54,699) - - (53,011)
Payment for crude oil pipeline, gathering and terminal assets - - (1,850) - (1,850)
Cash received from the sale of oil and natural gas properties 3,066 - - - 3,066
Payment for additions to other property and other assets - - (701) - (701)
--------- --------- --------- -------- --------
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES 4,754 (54,699) (2,551) - (52,496)
--------- --------- --------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Advances/investments with affiliates (49,054) 46,414 2,640 - -
Proceeds from long-term debt 263,723 - - - 263,723
Proceeds from common stock 1,785 - - - 1,785
Costs incurred to redeem long-term debt (6,468) - - - (6,468)
Principal payments of long-term debt (206,144) (42,000) - - (248,144)
Other 572 (896) (696) - (1,020)
--------- --------- --------- -------- --------
NET CASH PROVIDED BY FINANCING ACTIVITIES 4,414 3,518 1,944 - 9,876
--------- --------- --------- -------- --------
Net increase (decrease) in cash and cash equivalents 1,334 (3,714) (34) (1,198) (3,612)
Cash and cash equivalents, beginning of period 3,342 3,943 983 (2,139) 6,129
--------- --------- --------- -------- --------
Cash and cash equivalents, end of period $ 4,676 $ 229 $ 949 $ (3,337) $ 2,517
========= ========= ========= ========= =========
</TABLE>
F-38
