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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-Q
|X| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2003
OR
| | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
COMMISSION FILE NUMBER: 0-9808
PLAINS RESOURCES INC.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 13-2898764
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)
500 DALLAS STREET, SUITE 700
HOUSTON, TEXAS 77002
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)
(ZIP CODE)
(713) 739-6700
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes |X| No | |
Indicate by check mark whether the registrant is an accelerated filer (as
defined by Rule 12b-2 of the Exchange Act). Yes |X| No | |
23,729,552 shares of common stock, $0.10 par value,
issued and outstanding at April 30, 2003.
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PLAINS RESOURCES INC. AND SUBSIDIARIES
TABLE OF CONTENTS
PAGE
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements:
Consolidated Balance Sheets (Unaudited)
March 31, 2003 and December 31, 2002.............................................................. 3
Consolidated Statements of Income (Unaudited)
For the three months ended March 31, 2003 and 2002................................................ 4
Consolidated Statements of Cash Flows (Unaudited)
For the three months ended March 31, 2003 and 2002................................................ 5
Consolidated Statements of Comprehensive Income (Unaudited)
For the three months ended March 31, 2003 and 2002................................................ 6
Consolidated Statements of Changes in Stockholders' Equity (Unaudited)
For the three months ended March 31, 2003......................................................... 7
Notes to Consolidated Financial Statements (Unaudited)................................................. 8
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.......... 17
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk..................................... 29
ITEM 4. Controls and Procedures........................................................................ 31
PART II. OTHER INFORMATION............................................................................. 32
2
PLAINS RESOURCES INC.
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(IN THOUSANDS)
MARCH 31, DECEMBER 31,
2003 2002
--------- ------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 8,111 $ 8,807
Accounts receivable - Plains All American Pipeline, L.P. 2,170 --
Other accounts receivable 650 1,589
Inventory 1,785 2,305
Other current assets 1,050 1,515
--------- ---------
13,766 14,216
--------- ---------
PROPERTY AND EQUIPMENT, AT COST
Oil and gas properties - full cost method
Subject to amortization 351,152 349,517
Other property and equipment 27 27
--------- ---------
351,179 349,544
Less allowance for depreciation, depletion and amortization (297,443) (299,214)
--------- ---------
53,736 50,330
--------- ---------
INVESTMENT IN PLAINS ALL AMERICAN PIPELINE, L.P. 80,632 70,042
--------- ---------
OTHER ASSETS
Deferred income taxes 11,464 16,957
Other 9,864 9,867
--------- ---------
21,328 26,824
--------- ---------
$ 169,462 $ 161,412
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable $ 1,458 $ 1,361
Taxes payable 3,642 1,878
Royalties payable 404 348
Interest payable 127 78
Current maturities of long-term debt 18,000 18,000
Other current liabilities 4,054 4,522
--------- ---------
27,685 26,187
--------- ---------
LONG-TERM BANK DEBT 22,500 27,000
--------- ---------
ASSET RETIREMENT OBLIGATION 1,900 --
--------- ---------
OTHER LONG-TERM LIABILITIES 2,846 2,716
--------- ---------
STOCKHOLDERS' EQUITY
Series D cumulative convertible preferred stock 23,300 23,300
Common stock 2,827 2,806
Additional paid-in capital 274,352 273,162
Retained earnings (deficit) (96,908) (103,882)
Accumulated other comprehensive income (376) (2,862)
Treasury stock, at cost (88,664) (87,015)
--------- ---------
114,531 105,509
--------- ---------
$ 169,462 $ 161,412
========= =========
See notes to consolidated financial statements.
3
PLAINS RESOURCES INC.
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
(IN THOUSANDS, EXCEPT PER SHARE DATA)
THREE MONTHS ENDED
MARCH 31
--------------------
REVENUES 2003 2002
-------- --------
Oil sales to Plains All American Pipeline, L.P. $ 7,277 $ 4,179
Hedging (307) (123)
-------- --------
6,970 4,056
-------- --------
COSTS AND EXPENSES
Production expenses 1,858 1,393
Production and ad valorem taxes 404 103
Oil transportation expenses 1,118 939
General and administrative 1,812 1,667
Depreciation, depletion and amortization 1,405 1,159
Accretion of asset retirement obligation 56 --
-------- --------
6,653 5,261
-------- --------
OTHER INCOME (EXPENSE)
Equity in earnings of Plains All American Pipeline, L.P. 6,325 4,350
Gain on Plains All American Pipeline, L.P. unit offering 6,108 --
Gain (loss) on derivatives
Change in fair value 666 --
Cash settlements (732) --
Interest expense (501) (1,687)
Interest and other income 75 19
-------- --------
11,941 2,682
-------- --------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 12,258 1,477
Income tax benefit (expense)
Current (2,391) 2,768
Deferred (3,476) (3,513)
-------- --------
INCOME FROM CONTINUING OPERATIONS 6,391 732
Income from discontinued operations, net of tax -- 5,864
-------- --------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE 6,391 6,596
Cumulative effect of accounting change, net of tax 933 --
-------- --------
NET INCOME 7,324 6,596
Preferred dividends (350) (350)
-------- --------
INCOME AVAILABLE TO COMMON STOCKHOLDERS $ 6,974 $ 6,246
======== ========
EARNINGS PER SHARE (IN DOLLARS)
Basic
Income from continuing operations $ 0.25 $ 0.02
Discontinued operations -- 0.25
Change in accounting policy 0.04 --
-------- --------
$ 0.29 $ 0.27
======== ========
Diluted
Income from continuing operations $ 0.24 $ 0.02
Discontinued operations -- 0.24
Change in accounting policy 0.04 --
-------- --------
$ 0.28 $ 0.26
======== ========
Weighted average shares outstanding
Basic 23,981 23,635
Diluted 26,050 24,160
See notes to consolidated financial statements.
4
PLAINS RESOURCES INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(IN THOUSANDS)
THREE MONTHS ENDED
MARCH 31,
--------------------
2003 2002
-------- --------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 7,324 $ 6,596
Items not affecting cash flows from continuing operating activities
Income from discontinued operations, net of taxes -- (5,864)
Depreciation, depletion and amortization 1,405 1,159
Accretion of asset retirement obligation 56 --
Equity in earnings of Plains All American Pipeline, L.P. (6,325) (4,350)
Gain on Plains All American Pipeline, L.P. unit offering (6,108) --
Distributions received from Plains All American Pipeline, L.P. 7,504 6,958
Deferred income taxes 3,476 3,513
Cumulative effect of adoption of SFAS 143 (933) --
Change in derivative fair value (666) --
Noncash compensation expense 717 --
Other noncash items 16 673
Change in assets and liabilities from operating activities (43) (14,618)
-------- --------
Net cash provided by (used in) continuing activities 6,423 (5,933)
Net cash provided by (used in) discontinued activities -- 9,538
-------- --------
Net cash provided by (used in) operating activities 6,423 3,605
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties (549) (556)
Additions to other property and equipment -- (17)
Investment in Plains All American Pipeline, L.P. (589) --
-------- --------
Net cash provided by (used in) continuing activities (1,138) (573)
Net cash provided by (used in) discontinued activities -- (23,961)
-------- --------
Net cash provided by (used in) investing activities (1,138) (24,534)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Principal payments on long-term debt (4,500) --
Net change in revolving credit facility -- 19,500
Proceeds from exercise of stock options 606 1,618
Treasury stock purchases (1,649) --
Costs incurred in connection with financing arrangements (88) --
Preferred stock dividends (350) (350)
-------- --------
Net cash provided by (used in) continuing activities (5,981) 20,768
Net cash provided by (used in) discontinued activities -- --
-------- --------
Net cash provided by (used in) financing activities (5,981) 20,768
-------- --------
Net increase (decrease) in cash and cash equivalents (696) (161)
Cash and cash equivalents, beginning of period 8,807 1,179
-------- --------
Cash and cash equivalents, end of period $ 8,111 $ 1,018
======== ========
See notes to consolidated financial statements
5
PLAINS RESOURCES INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
(IN THOUSANDS)
THREE MONTHS ENDED
MARCH 31,
--------------------
2003 2002
-------- --------
NET INCOME $ 7,324 $ 6,596
OTHER COMPREHENSIVE INCOME (LOSS):
From continuing operations:
Commodity hedging contracts:
Change in fair value (643) (742)
Reclassification adjustment for settled contracts 155 (10)
Interest rate swap -- 30
Equity in other comprehensive income changes of Plains All
American Pipeline, L.P. 2,974 (447)
-------- --------
2,486 (1,169)
From discontinued operations -- (23,178)
-------- --------
2,486 (24,347)
-------- --------
COMPREHENSIVE INCOME $ 9,810 $(17,751)
======== ========
See notes to consolidated financial statements.
6
PLAINS RESOURCES INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (UNAUDITED)
(IN THOUSANDS)
THREE MONTHS ENDED
MARCH 31, 2003
---------------------
SHARES AMOUNT
--------- ---------
SERIES D CUMULATIVE CONVERTIBLE PREFERRED STOCK
Balance, beginning and end of period 47 $ 23,300
========= ---------
COMMON STOCK
Balance, beginning of period 28,048 2,806
Common stock issued upon exercise of
stock options and other 217 21
--------- ---------
Balance, end of period 28,265 2,827
========= ---------
ADDITIONAL PAID-IN CAPITAL
Balance, beginning of period 273,162
Common stock issued upon exercise of
stock options and other 1,190
---------
Balance, end of period 274,352
---------
RETAINED EARNINGS (DEFICIT)
Balance, beginning of period (103,882)
Net income 7,324
Preferred stock dividends (350)
---------
Balance, end of period (96,908)
---------
ACCUMULATED OTHER COMPREHENSIVE INCOME
Balance, beginning of period (2,862)
Other comprehensive income 2,486
---------
Balance, end of period (376)
---------
TREASURY STOCK
Balance, beginning of period 3,854 (87,015)
Purchase of treasury shares 143 (1,649)
--------- ---------
Balance, end of period 3,997 (88,664)
========= ---------
TOTAL $ 114,531
=========
See notes to consolidated financial statements.
7
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
NOTE 1 -- ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION
The consolidated financial statements of Plains Resources Inc. ("Plains",
"our", or "we") include the accounts of all wholly owned subsidiaries. All
adjustments, consisting only of normal recurring adjustments, that in the
opinion of management were necessary for a fair statement of the results for the
interim periods, have been reflected. All significant intercompany transactions
have been eliminated. Certain reclassifications have been made to prior year
statements to conform to the current year presentation.
We are an independent energy company. We are principally engaged in the
"midstream" activities of marketing, gathering, transporting, terminalling, and
storage of oil through our equity ownership in Plains All American Pipeline,
L.P. ("PAA"), a publicly traded master limited partnership that is actively
engaged in the midstream energy markets. All of PAA's midstream activities are
conducted in the United States and Canada. We also participate in the "upstream"
activities of acquiring, exploiting, developing, exploring for and producing oil
through our wholly-owned subsidiary, Calumet Florida L.L.C., which has producing
properties in the Sunniland Trend in south Florida.
These consolidated financial statements and related notes present our
consolidated financial position as of March 31, 2003 and December 31, 2002, the
results of our operations, our cash flows and our comprehensive income for the
three months ended March 31, 2003 and 2002 and the changes in our stockholders'
equity for the three months ended March 31, 2003. The results for the three
months ended March 31, 2003, are not necessarily indicative of the final results
to be expected for the full year. These financial statements have been prepared
pursuant to the rules and regulations of the Securities and Exchange Commission
regarding interim financial reporting. Accordingly, they do not include all of
the information and notes required by accounting principles generally accepted
in the United States of America for complete financial statements and should be
read in conjunction with the audited consolidated financial statements included
in our Annual Report on Form 10-K for the year ended December 31, 2002.
On December 18, 2002 we distributed 100 percent of the common shares of
Plains Exploration & Production Company ("PXP"), our wholly-owned subsidiary
that owned oil and gas properties offshore and onshore California and in
Illinois, to our stockholders (the "spin-off"). As a result of the spin-off, the
historical results of the operations of PXP are reflected in our financial
statements as "discontinued operations". In connection with the spin-off we
entered into certain agreements with PXP, see Note 7.
ACCOUNTING POLICIES
Asset Retirement Obligations. Effective January 1, 2003 we adopted Statement
of Financial Accounting Standards No. 143, "Accounting for Asset Retirement
Obligations" ("SFAS 143"). SFAS 143 requires entities to record the fair value
of a liability for a legal obligation to retire an asset in the period in which
the liability is incurred. A legal obligation is a liability that a party is
required to settle as a result of an existing or enacted law, statute, ordinance
or contract. When the liability is initially recorded, the entity should
capitalize the retirement cost of the related long-lived asset. Each period the
liability is accreted to its then present value, and the capitalized cost is
depreciated over the useful life of the related asset. If the liability is
settled for an amount other than the recorded amount, a gain or loss is
recognized at the time of settlement. In prior periods we included estimated
future costs of abandonment and dismantlement in our full cost amortization base
and these costs were amortized as a component of our depletion expense.
At January 1, 2003 the present value of our future Asset Retirement
Obligation for oil and gas properties and equipment was $2.6 million. The
cumulative effect of our adoption of SFAS No. 143 and the change in accounting
principle resulted in an increase in income during the first quarter of 2003 of
$0.9 million (reflecting a $2.8 million decrease in accumulated DD&A, partially
offset by $1.3 million in accretion expense, and $0.6 million deferred income
tax expense). We recorded a liability of $2.6 million and an asset of $1.2
million in connection with the adoption of SFAS 143. There will be no impact on
our cash flows as a result of adopting SFAS No. 143.
8
The following table illustrates the changes in our asset retirement
obligation during the period (in thousands):
THREE MONTHS ENDED
MARCH 31,
-----------------
2003 2002
------- ------
Pro forma
Asset retirement obligation - beginning of period $ 2,556 $2,403
Accretion expense 56 52
Asset retirement costs incurred (138) --
------- ------
Asset retirement obligation - end of period $ 2,474 $2,455
======= ======
On a pro forma basis the effect of the adoption of SFAS 143 on our income
from continuing operations, our net income and our earnings per share for the
three months ended March 31, 2002 is not material.
Inventory. Our oil inventory is stated at the lower of cost to produce or
market value. Materials and supplies inventory is carried at the lower of cost
or market with cost determined on an average cost method. Inventory consists of
the following (in thousands):
MARCH 31, DECEMBER 31,
2003 2002
--------- ---------
Oil $ 962 $ 1,482
Materials and supplies 823 823
--------- ---------
$ 1,785 $ 2,305
========= =========
9
Other Assets. Other assets consists of the following (in thousands):
MARCH 31, DECEMBER 31,
2003 2002
---------- ----------
Restricted cash $ 5,000 $ 5,000
Debt issue costs, net 616 612
Receivable from PXP 3,202 3,202
Other 1,046 1,053
---------- ----------
$ 9,864 $ 9,867
========== ==========
Stock-Based Employee Compensation. Statement of Financial Accounting
Standards No. 123 "Accounting for Stock-Based Compensation" ("SFAS 123")
established financial accounting and reporting standards for stock-based
employee compensation. SFAS 123 defines a fair value based method of accounting
for an employee stock option or similar equity instrument. SFAS 123 also allows
an entity to continue to measure compensation cost for those instruments using
the intrinsic value-based method of accounting prescribed by Accounting
Principles Bulletin No. 25 "Accounting for Stock Issued to Employees" ("APB
25"). We have elected to follow APB 25 and related interpretations in accounting
for our employee stock options. Under APB 25, if the exercise price of our
employee stock options equals the market price of the underlying stock on the
date of grant, no compensation expense is recognized in the financial
statements. The compensation expense recorded under APB 25 for our restricted
stock awards is the same as that determined under SFAS 123.
Set forth below is a summary of our net income and earnings per share as
reported and pro forma as if the fair value based method of accounting defined
in SFAS 123 had been applied (in thousands, except per share data).
THREE MONTHS ENDED
MARCH 31,
----------------------
2003 2002
--------- ---------
Net income, as reported $ 6,974 $ 6,246
Add: Stock-based employee compensation
expense included in reported net income,
net of related tax effects 351 199
Deduct: Total stock-based employee
compensation expense determined
under fair value based method for all
awards, net of related tax effects (815) (421)
--------- ---------
Pro forma net income $ 6,510 $ 6,024
========= =========
Earnings per share:
Basic-as reported $ 0.29 $ 0.27
========= =========
Basic-pro forma $ 0.27 $ 0.25
========= =========
Diluted-as reported $ 0.28 $ 0.26
========= =========
Diluted-pro forma $ 0.26 $ 0.25
========= =========
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 2002: risk-free interest rate of 3.0%; a volatility
factor of the expected market price of our common stock of 0.33; no expected
dividends; and weighted average expected option life of 4.4 years. No options
were granted during the three months ended March 31, 2003. For purposes of pro
forma disclosures, the estimated fair value of the options is amortized to
expense over the options' vesting period.
10
Recent Accounting Pronouncements. The Financial Accounting Standards Board
issued Statement of Financial Accounting Standards No. 149 "Amendment of
Statement 133 on Derivative Instruments and Hedging Activities" on April 30,
2003. The statement is effective for contracts entered into or modified after
June 30, 2003 and for hedging relationships designated after June 30, 2003. At
this time, we cannot reasonably estimate the effect of the adoption of SFAS No.
149 on either our financial position or results of operations.
NOTE 2 -- INVESTMENT IN PLAINS ALL AMERICAN PIPELINE, L.P.
In March 2003, PAA issued 2.6 million common units in a public equity
offering. We recognized a gain of $6.1 million resulting from the increase in
the book value of our equity in PAA to reflect our proportionate share of the
increase in the underlying net assets of PAA due to the sale of the units. As a
result of the offering, we made a general partner capital contribution of
approximately $0.6 million.
At March 31, 2003, our aggregate 24% ownership in PAA consisted of: (i) a
44% ownership interest in the 2% general partner interest and incentive
distribution rights, (ii) 45%, or approximately 4.5 million, of the subordinated
units and (iii) 19%, or approximately 7.9 million, of the common units
(including approximately 1.3 million Class B common units).
PAA FINANCIAL STATEMENT INFORMATION
The following table presents summarized financial statement information of
PAA (in thousands of dollars):
THREE MONTHS ENDED
MARCH 31,
-----------------------
2003 2002
---------- ----------
Revenues $3,281,908 $1,545,323
Cost of sales and operations 3,224,356 1,506,935
Gross margin, excluding depreciation 57,552 38,388
Operating income 33,609 20,663
Net income 24,351 14,281
MARCH 31, DECEMBER 31,
2003 2002
---------- ----------
Current assets $ 583,114 $ 602,935
Property and equipment, net 1,013,034 952,753
Other assets 120,387 110,887
Total assets 1,716,535 1,666,575
Current liabilities 587,692 637,249
Long-term debt 523,151 509,736
Other long-term liabilities 14,112 7,980
Partners' capital 591,580 511,610
Total liabilities and partners' capital 1,716,535 1,666,575
11
NOTE 3 -- DISCONTINUED OPERATIONS
The results of operations of PXP, which have been reclassified as
discontinued operations for the three months ended March 31, 2002, are
summarized as follows (in thousands):
THREE MONTHS ENDED
MARCH 31, 2002
------------------
Revenues $ 40,673
Costs and expenses (26,372)
--------
Income from operations 14,301
Other income (expense) (4,674)
--------
Income before income taxes 9,627
Income tax expense (3,763)
--------
Income from discontinued operations $ 5,864
========
NOTE 4 -- DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
We have entered into various derivative instruments to reduce our exposure
to fluctuations in the market price of oil. The derivative instruments consist
primarily of oil swap and option contracts entered into with financial
institutions. Derivative instruments are accounted for in accordance with SFAS
No. 133 "Accounting for Derivative Instruments and Hedging Activities" as
amended by SFAS 137 and SFAS 138, or SFAS 133. All derivative instruments are
recorded on the balance sheet at fair value. If the derivative does not qualify
as a hedge or is not designated as a hedge, the gain or loss on the derivative
is recognized currently in earnings. If the derivative qualifies for hedge
accounting, the gain or loss on the derivative is deferred in Accumulated Other
Comprehensive Income ("OCI"), a component of our stockholders' equity, to the
extent the hedge is effective. Gains and losses on oil hedging instruments
related to OCI and adjustments to carrying amounts on hedged volumes are
included in oil revenues in the period that the related volumes are delivered.
The relationship between the hedging instrument and the hedged item must be
highly effective in achieving the offset of changes in cash flows attributable
to the hedged risk both at the inception of the contract and on an ongoing
basis. Hedge accounting is discontinued prospectively when a hedge instrument
becomes ineffective. Gains and losses deferred in OCI related to cash flow
hedges that become ineffective remain unchanged until the related product is
delivered. If it is determined that it is probable that a hedged forecasted
transaction will not occur, deferred gains or losses on the hedging instrument
are recognized in earnings immediately.
We formally document all relationships between hedging instruments and
hedged items, as well as our risk management objectives and strategy for
undertaking the hedge. Hedge effectiveness is measured at least on a quarterly
basis. This process includes specific identification of the hedging instrument
and the hedged item, the nature of the risk being hedged and how the hedging
instrument's effectiveness will be assessed. Both at the inception of the hedge
and on an ongoing basis, we assess whether the derivatives that are used in
hedging transactions are highly effective in offsetting changes in cash flows of
hedged items.
In the first quarter of 2003, the NYMEX oil price and the price we received
for our Florida oil production did not correlate closely enough for the hedges
to qualify for hedge accounting. As a result, we were required to discontinue
hedge accounting effective February 1, 2003 and reflect the mark-to-market value
of the hedges in earnings prospectively from that date. In the two months ended
March 31, 2003 we recorded a $0.7 million gain for the increase in the fair
value of our derivatives and recognized a $0.7 million loss on cash settlements
of such derivatives. Cash settlements of $0.3 million for January 2003 are
reflected as a reduction of revenues.
At March 31, 2003 Accumulated OCI consisted of unrealized losses of $1.5
million ($0.7 million, net of tax) on our oil hedging instruments, $0.5 million
($0.3 million, net of tax) related to pension liabilities and an unrealized gain
of $1.3 million ($0.6 million, net of tax) related to our equity in the OCI
gains of PAA. At March 31, 2003, the liability related to our open oil hedging
instruments was included in current liabilities ($1.3 million), other long-term
liabilities ($0.1 million), and deferred income taxes (a tax benefit of $0.7
million).
12
During the first quarter of 2002 oil sales revenues were reduced by $0.1
million for non-cash expense related to the amortization of option premiums. As
of March 31, 2003, $1.3 million ($0.7 million, net of tax) of deferred net
losses on our oil hedging instruments recorded in OCI are expected to be
reclassified to earnings during the following twelve months.
At March 31, 2003 we had the following open oil derivative positions:
BARRELS PER DAY
-------------------
2003 2004
------ ------
Swaps
Average price $26.10/bbl 1,500 --
Average price $24.07/bbl -- 1,000
Location and quality differentials attributable to our properties are not
included in the foregoing prices. Because of the quality and location of our oil
production, these adjustments will reduce our net price per barrel.
NOTE 5 -- LONG-TERM DEBT AND CREDIT FACILITIES
SECURED TERM LOAN FACILITY
In December 2002 we entered into a $45.0 million secured term loan facility
with a group of banks. The term loan is repayable in 10 quarterly installments
of $4.5 million commencing on February 28, 2003 with a final maturity of May 31,
2005. Amounts outstanding under the term loan bear an annual interest rate, at
our election, equal to either the Base Rate (as defined in the agreement) plus
1.5%, or LIBOR plus 3%. The term loan requires that we maintain $5.0 million on
deposit in a debt service reserve account with one of the lending banks. At
March 31, 2003 $40.5 million was outstanding under the terms of the secured term
loan facility. Our average borrowing rate for the three months ended March 31,
2003 was 4.7% (4.4% at March 31, 2003).
To secure the term loan, we pledged 100% of the shares of stock of our
subsidiaries and pledged 4,950,000 of our PAA common units. To the extent that
the outstanding principal under the term loan exceeds the balance in the debt
service reserve account plus 50% of the fair market value of the pledged common
units, we are required to repay the excess. The fair market value of the pledged
units is determined based on the closing price of PAA common units as reported
on the New York Stock Exchange.
The term loan contains covenants that limit our ability, as well as the
ability of our subsidiaries, to incur additional debt, make investments, create
liens, enter into leases, sell assets, change the nature of our business or
operations, guarantee other indebtedness, enter into certain types of hedge
agreements, enter into take-or-pay arrangements, merge or consolidate and enter
into transactions with affiliates. In addition, if an event of default exists,
the term loan prohibits us from paying dividends or repurchasing or redeeming
shares of any class of capital stock. The term loan requires us to maintain a
minimum consolidated tangible net worth ($82.7 million at March 31, 2003) and a
consolidated debt service coverage ratio (as defined in the agreement) of 1.0 to
1.0. At March 31, 2003 we were in compliance with the covenants contained in the
term loan facility.
13
NOTE 6 -- EARNINGS PER SHARE
The following is a reconciliation of the numerators and denominators of the
basic and diluted earnings per share computations for income from continuing
operations before the cumulative effect of accounting changes for the three
months ended March 31, 2003 and 2002 (in thousands, except per share amounts):
THREE MONTHS ENDED MARCH 31,
------------------------------------------
2003 2002
------------------- --------------------
BASIC DILUTED BASIC DILUTED
-------- ------- -------- --------
Income from continuing operations $ 6,391 $ 6,391 $ 732 $ 732
Preferred dividends (350) -- (350) (350)
-------- ------- -------- --------
Income from continuing operations available
to common stockholders 6,041 6,391 382 382
Income from discontinued operations, net of tax -- -- 5,864 5,864
Effect of accounting changes, net of tax 933 933 -- --
-------- ------- -------- --------
Net income available to common stockholders $ 6,974 $ 7,324 $ 6,246 $ 6,246
======== ======= ======== ========
Weighted average number of shares of
common stock outstanding 23,981 23,981 23,635 23,635
Effect of dilutive securities
Convertible preferred stock -- 1,671 -- --
Employee stock options and restricted stock -- 398 -- 525
-------- ------- -------- --------
Average common shares, including dilutive effect 23,981 26,050 23,635 24,160
======== ======= ======== ========
Earnings per share
Continuing operations $ 0.25 $ 0.24 $ 0.02 $ 0.02
Discontinued operations -- -- 0.25 0.24
Effect of accounting changes 0.04 0.04 -- --
-------- ------- -------- --------
Net income available to common stockholders $ 0.29 $ 0.28 $ 0.27 $ 0.26
======== ======= ======== ========
In 2002 our cumulative convertible preferred stock was not included in the
computation of diluted earnings per share because the effect was antidilutive.
NOTE 7 -- RELATED PARTY TRANSACTIONS
GOVERNANCE OF PAA
We, along with Sable Investments, L.P. (which is owned by Mr. Flores, our
Chairman, and Mr. Raymond, our Chief Executive Officer and President), Kafu
Holdings, L.P. (which is controlled by Kayne Anderson Capital Advisors, L.P. and
Kayne Anderson Investment Management, Inc., of which Mr. Sinnott, our director,
is Senior Vice President), and E-Holdings III, L.P. (which is controlled by
EnCap Investments L.L.C. and of which Mr. Phillips, our director, is a managing
director and principal) are parties to agreements governing Plains All American
GP LLC, which is the general partner of Plains AAP, L.P., and Plains AAP, L.P.,
which is the general partner of PAA. These agreements govern the ongoing
management of PAA.
In addition, the general partner of PAA is owned as follows:
Plains Resources 44.00%
Sable Investments, L.P. 20.00%
Kafu Holdings, L.P. 16.42%
E-Holdings, L.P. 9.00%
Others 10.58%
------
100.00%
======
14
Also, each of we, Sable Investments, Kafu Holdings, and E-Holdings may
appoint one member of the Plains All American GP LLC board of directors.
VALUE ASSURANCE AGREEMENTS
We entered into a value assurance agreement with each of Sable Investments,
Kafu Holdings and E-Holdings with respect to the subordinated units they
acquired from us in our June 2001 strategic restructuring. The value assurance
agreements require us to pay to them an amount per fiscal year, payable on a
quarterly basis, equal to the difference between $1.85 per unit and the actual
amount distributed during that period. The value assurance agreements will
expire upon the earlier of the conversion of the subordinated units to common
units, or June 8, 2006.
OIL MARKETING AGREEMENT
PAA is the exclusive marketer/purchaser for all of our equity oil
production. The marketing agreement provides that PAA will purchase for resale
at market prices all of our equity oil production for which PAA charges a fee of
$0.20 per barrel. For the three months ended March 31, 2003 and 2002, PAA paid
approximately $8.6 million and $4.9 million, respectively, for the purchase of
oil under the agreement, including the royalty share of production. For the
three months ended March 31, 2003 and 2002, we paid PAA approximately $47,000
and $49,000, respectively, in marketing fees.
We are currently negotiating a new marketing agreements with PAA to, among
other things, add a definitive term to the agreement and provide that PAA will
use its reasonable best efforts to obtain the best price for our oil production.
AGREEMENTS WITH PXP
In connection with the reorganization and the spin-off we entered into
certain agreements with PXP, including a master separation agreement; an
intellectual property agreement; the Plains Exploration & Production transition
services agreement; the Plains Resources transition services agreement; and a
technical services agreement. For the three months ended March 31, 2003 PXP
billed us $136,000 for services provided to us under these agreements and we
billed PXP $38,000 for services we provided under these agreements.
OTHER
From time to time we charter private aircraft from Gulf Coast Aviation Inc.
("Gulf Coast"), which is not affiliated with us or our employees. On certain
occasions, the aircraft that Gulf Coast charters is owned by our Chairman of the
Board. In the three months ended March 31, 2003 and 2002 we paid Gulf Coast
$10,000 and $146,000, respectively, for aircraft chartering services provided by
Gulf Coast using an aircraft owned by our Chairman. The charters were arranged
through arms-length dealings with Gulf Coast and the rates were market based.
NOTE 8 -- COMMITMENTS AND CONTINGENCIES
On September 18, 2002 Stocker Resources Inc., or Stocker, the general
partner of PXP before it was converted from a limited partnership to a
corporation, filed a declaratory judgment action against Commonwealth Energy
Corporation, or Commonwealth, in the Superior Court of Orange County, California
relating to the termination of an electric service contract. Stocker is seeking
a declaratory judgment that it was entitled to terminate the contract and that
Commonwealth has no basis for proceeding against Stocker's related $1.5 million
performance bond. Also on September 18, 2002, Stocker was named a defendant in
an action brought by Commonwealth in the Superior Court of Orange County,
California for breach of the electric service contract. Commonwealth is seeking
unspecified damages. The two cases have been consolidated and set for trial in
December 2003. Stocker was merged into us in December 2002. Under our master
separation agreement with PXP, we are indemnified for damages we incur as a
result of this action. We intend to defend our rights vigorously in this matter.
We, in the ordinary course of business, are a claimant and/or defendant in
various other legal proceedings. We do not believe that the outcome of these
legal proceedings, individually and in the aggregate, will have a materially
adverse effect on our financial condition, results of operations or cash flows.
15
NOTE 9 -- SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Selected cash payments and noncash activities were as follows (in
thousands):
THREE MONTHS ENDED
MARCH 31,
------------------
2003 2002
-------- -------
Cash paid for interest $ 444 $14,437
======== =======
Cash paid for taxes $ 665 $ 2,744
======== =======
Noncash sources of investing and financing activities:
Tax benefit from exercise of employee stock options $ 115 $ 545
======== =======
16
ITEM 2. - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following information should be read in connection with the information
contained in the consolidated financial statements and notes thereto included
elsewhere in this report.
We are an independent energy company. We are principally engaged in the
"midstream" activities of marketing, gathering, transporting, terminalling, and
storage of oil through our equity ownership in Plains All American Pipeline,
L.P.,PAA. PAA is a publicly traded master limited partnership actively engaged
in the midstream energy markets. As of March 31, 2003 we owned 44% of the
general partner of PAA and 12.4 million limited partner units of PAA, which
represented approximately 24% aggregate ownership interest in PAA. We also
participate in the "upstream" activities of acquiring, exploiting, developing,
exploring for and producing oil through our wholly-owned subsidiary, Calumet
Florida L.L.C., which has producing properties in the Sunniland Trend in south
Florida.
The book value of our investment in PAA represents 48% of our total assets
as of March 31, 2003 and the book value of our Florida oil properties represents
32%. As of December 31, 2002, the present value of our proved oil reserves was
approximately $87.9 million. We own 6.6 million common units, 1.3 million Class
B common units and 4.5 million subordinated units of PAA. The closing price of
publicly traded PAA common units, as reported on the New York Stock Exchange,
was $24.80 on March 31, 2003. The Class B common units and the subordinated
units are not publicly traded but do receive cash distributions from PAA. PAA's
partnership agreement contains provisions which, upon the occurrence of certain
future events, will result in the conversion of the subordinated units to common
units. During the first quarter of 2003 we had oil revenues of $7.3 million and
distributions received from PAA attributable to our general and limited partner
interests totaled $7.5 million. PAA's financial performance directly impacts our
financial performance and the market value performance of PAA's limited partner
interests directly impacts the value of our assets. As a result, we encourage
you to review PAA's SEC filings, including its Annual Report on Form 10-K for
the year ended December 31, 2002 and it Quarterly Report on Form 10-Q for the
quarter ended March 31, 2003, to review and assess, among other things, PAA's
financial performance and financial condition, PAA's business, operations, and
competition, and risk factors associated with PAA's business.
SPIN-OFF OF PLAINS EXPLORATION & PRODUCTION COMPANY
On December 18, 2002 we distributed 100 percent of the common shares of
Plains Exploration & Production Company, or PXP, our wholly-owned subsidiary
that owned oil and gas properties offshore and onshore California and in
Illinois, to our stockholders, the spin-off. As a result of the spin-off, the
historical results of the operations of PXP are reflected in our financial
statements as "discontinued operations". Except where noted, discussions in this
Form 10-Q with respect to oil and gas operations relate to our activities other
than the discontinued operations.
GENERAL
UPSTREAM OPERATIONS
We follow the full cost method of accounting whereby all costs associated
with property acquisition, exploration, exploitation and development activities
are capitalized. Our revenues are derived from the sale of oil. We recognize
revenues when our production is sold and title is transferred. Our revenues are
highly dependent upon the prices of, and demand for oil. Historically, the
markets for oil have been volatile and are likely to continue to be volatile in
the future. The prices we receive for our oil and our levels of production are
subject to wide fluctuations and depend on numerous factors beyond our control,
including supply and demand, economic conditions, foreign imports, the actions
of OPEC, political conditions in other oil-producing countries, and governmental
regulation, legislation and policies. Under the SEC's full cost accounting
rules, we review the carrying value of our proved oil and gas properties each
quarter. These rules generally require that we price our future oil and gas
production at the oil and gas prices in effect at the end of each fiscal quarter
to determine a ceiling value of our properties. The rules require a write-down
if our capitalized costs exceed the allowed "ceiling." We have had no
write-downs due to these ceiling test limitations since 1998. Given the
volatility of oil prices, it is likely that our estimate of discounted future
net revenues from proved oil and gas reserves will fluctuate in the near term.
If oil prices decline in the future, write-downs of our oil and gas properties
could occur. Write-downs required by these rules do not directly impact our cash
flows from operating activities. Decreases in oil and gas prices have had, and
will likely have in the future, an adverse effect on the carrying value of our
proved reserves and our revenues, profitability and cash flow.
17
To manage our exposure to commodity price risks, we use various derivative
instruments to hedge our exposure to oil sales price fluctuations. Our hedging
arrangements provide us protection on the hedged volumes if oil prices decline
below the prices at which these hedges are set. However, if oil prices increase,
ceiling prices in our hedges may cause us to receive lower revenues on the
hedged volumes than we would receive in the absence of hedges. Gains and losses
from hedging transactions are recognized as revenues when the associated
production is sold. The relationship between the hedging instrument and the
hedged item must be highly effective in achieving the offset of changes in cash
flows attributable to the hedged risk both at the inception of the contract and
on an ongoing basis. Hedge accounting is discontinued prospectively when a hedge
instrument becomes ineffective and changes in value are reflected in earnings
prospectively from the date the hedge becomes ineffective. Gains and losses
deferred in other comprehensive income, or OCI, related to cash flow hedges that
become ineffective remain unchanged until the related product is delivered.
Our oil production expenses include salaries and benefits of personnel
involved in production activities, electric costs, maintenance costs,
production, ad valorem and severance taxes, and other costs necessary to operate
our producing properties. Depletion of capitalized costs of producing oil and
gas properties is provided using the units of production method based upon
proved reserves. For the purposes of computing depletion, proved reserves are
redetermined as of the end of each year and on an interim basis when deemed
necessary. General and administrative expenses consist primarily of salaries and
related benefits of administrative personnel, office rent, systems costs and
other administrative costs.
MIDSTREAM OPERATIONS
We account for our investment in PAA using the equity method of accounting.
We record equity in earnings of PAA based on our aggregate ownership interest,
as adjusted for general partner incentive distributions. Equity in earnings for
our general partner interest is based on our 44% share of 2% of PAA's net income
plus the amount of the general partner incentive distribution. Equity in
earnings for our limited partner units is based on our ownership percentage of
limited partner units (24% at March 31, 2003) multiplied by 98% of PAA's net
income less the general partner incentive distribution. Increased earnings
attributable to the general partner incentive distributions will be somewhat
offset because of our ownership of limited partner units. Cash distributions
received from PAA are not reflected in earnings, but reduce our investment in
PAA.
When PAA sells additional limited partner units and we do not purchase
additional units, our ownership interest in PAA is reduced, creating an "implied
sale" of a portion of our investment. We have recognized gains from PAA equity
issuances representing the difference between our carrying cost and the fair
value of the interest deemed sold.
18
RESULTS OF OPERATIONS
The following table reflects the components of our oil revenues from
continuing operations and sets forth our revenues and costs and expenses from
continuing operations on a BOE basis:
THREE MONTHS ENDED
MARCH 31,
--------------------
2003 2002
-------- --------
Production (MBbls) 232 247
Sales (MBbls) 276 216
Average NYMEX price per bbl $ 33.80 $ 21.63
Hedging and derivative cash settlements (3.76) (0.57)
Differential (7.44) (2.28)
-------- --------
Average realized price per bbl 22.60 18.78
Production expenses per bbl (6.73) (6.45)
Production and ad valorem taxes per bbl (1.46) (0.48)
Oil transportation expenses per bbl (4.05) (4.35)
-------- --------
Gross margin per bbl $ 10.36 $ 7.50
======== ========
DD&A per bbl (oil & gas properties) $ 4.68 $ 3.73
In the first quarter of 2003, the NYMEX oil price and the price we receive
for our Florida oil production did not correlate closely enough for our hedges
to qualify for hedge accounting. As a result, we were required to discontinue
hedge accounting effective February 1, 2003 and reflect the mark-to-market value
of the derivatives in earnings prospectively from that date. The $2.1 million
($1.0 million, net of tax) net loss in OCI at January 31, 2003 related to these
hedges will be recognized in earnings as the related production is delivered. We
will continue to include the cash settlements from the hedges in our realized
price calculations but will not consider the fair value gains and losses in the
realized price calculations. Derivative instruments that we enter into in the
future may or may not qualify for hedge accounting.
COMPARISON OF THREE MONTHS ENDED MARCH 31, 2003 TO THREE MONTHS ENDED MARCH 31,
2002
In 2003, we reported first quarter net income of $7.3 million compared to
net income of $6.6 million in the first quarter of 2002. Income from continuing
operations was $6.4 million in 2003 compared to $0.7 million for 2002. Results
for 2003 include a $3.1 million after-tax gain related to a PAA equity offering.
Oil revenues. Our oil revenues, excluding the effect of hedging, increased
74%, or $3.1 million, to $7.3 million for the first quarter of 2003 from $4.2
million for the first quarter of 2002. The increase was primarily due to
increased sales volumes that increased revenues by $1.6 million and higher
prices that increased revenues by $1.5 million.
We reported sales volumes from our Florida properties of 276 MBbls in 2003
compared to 216 MBbls in 2002. In accordance with SEC Staff Accounting Bulletin
101 we reflect revenue from oil production in the period it is sold as opposed
to when it is produced. Oil volumes decreased 6% on an "as produced" basis, with
production volumes of 232 MBbls in 2003 compared to 247 MBbls in 2002. The
location of our Florida properties and the timing of the barges that transport
the oil to market cause reported sales volumes to differ from production
volumes. Actual timing of sales volumes is difficult to predict. The Florida oil
is typically sold in shipments that range from approximately 110 MBbls to 140
MBbls and typically occurs every 30-50 days. In addition, our Florida properties
consist of a relatively low number of higher volume wells and downtime due to
equipment failures and other operational issues can cause production from this
area to be volatile.
Our average realized price for oil increased 20%, or $3.82, to $22.60 per
Bbl for the first quarter of 2003 from $18.78 per Bbl for the first quarter of
2003. The increase is primarily attributable to an improvement in the NYMEX oil
price, which averaged $33.80 per Bbl in 2003 versus $21.63 per Bbl in 2002. The
average differential for location and quality increased to $7.44 per Bbl in 2003
compared to $2.28 per Bbl in 2002. Hedging and derivatives had the effect of
decreasing our average price per Bbl by $3.76 in 2003 and $0.57 in 2002.
19
Production expenses. Our production expenses increased 33%, or $0.5 million,
to $1.9 million for the first quarter of 2003 from $1.4 million for the first
quarter of 2002 primarily due to increased sales volumes. Unit production
expenses for 2003 were $6.73 per Bbl compared to $6.45 in 2002. The per Bbl
increase is primarily attributable to increased fuel costs due to an increase in
diesel prices.
Production and ad valorem taxes. Our production and ad valorem taxes
increased 292%, or $0.3 million, to $0.4 million for the first quarter of 2003
from $0.1 million for the first quarter of 2002 primarily due to increased sales
prices and the expiration of severance tax exemptions for several wells in the
second quarter of 2002. Unit production and ad valorem taxes for 2003 were $1.46
per Bbl compared to $0.48 per Bbl in 2002.
Oil transportation expenses. Our oil transportation expenses increased 19%
to $1.1 million in the first quarter of 2003 from $0.9 million in the first
quarter of 2002 reflecting higher sales volumes. On a per barrel basis, oil
transportation expenses decreased from $4.35 in the first quarter of 2002 to
$4.05 in the first quarter of 2003.
General and administrative expense. Our general and administrative expense
increased 9%, or $0.1 million, to $1.8 million for the first quarter of 2003
from $1.7 million for the first quarter of 2002. The increase primarily reflects
$0.2 million of expenses in the first quarter of 2003 related to an acquisition
that was not consummated.
Depreciation, depletion and amortization. Our depreciation, depletion and
amortization, or DD&A expense increased 21%, or $0.2 million, to $1.4 million
for the first quarter of 2003 from $1.2 million for the first quarter of 2002.
The increase is due to an increase in the per unit DD&A rate ($4.68 per Bbl in
2003 versus $3.73 per Bbl in 2002) and higher sales volumes.
Accretion of asset retirement obligation. Accretion expense for the first
quarter of 2003 was $0.1 million. Accretion expense represents the adjustment of
our asset retirement obligation to its present value at the end of the period
based on our credit adjusted risk free rate.
Equity in earnings of Plains All American Pipeline, L.P. Our equity in
earnings of PAA increased $1.9 million to $6.3 million for the first quarter of
2003 from $4.4 million for the first quarter of 2002. PAA reported net income of
$24.4 million in the first quarter of 2003 compared to $14.3 million in the
first quarter of 2002.
Gain on Plains All American Pipeline, L.P. unit offerings. In the first
quarter of 2003 we recognized a noncash gain of $6.1 million due to the increase
in the book value of our equity in PAA to reflect our proportionate share of the
increase in the underlying net assets of PAA resulting from PAA's public equity
offering.
Gain (loss) on derivatives. As previously discussed, we were required to
discontinue hedge accounting effective February 1, 2003. As a result, in the two
months ended March 31, 2003 we recorded a $0.7 million gain for the increase in
the fair value of our derivatives and recognized a $0.7 million loss on cash
settlements of such derivatives.
Interest expense. Our interest expense decreased $1.2 million, to $0.5
million for the first quarter of 2003 from $1.7 million for the first quarter of
2002, primarily reflecting lower outstanding debt.
Income tax expense. Our income tax expense increased $5.2 million to $5.9
million for the first quarter of 2003 from $0.7 million for the first quarter of
2003. The increase was primarily due to higher pre-tax income from continuing
operations as our effective tax rate was 47.9% in the first quarter of 2003
compared to 50.4% in the first quarter of 2002.
Our effective tax rate reflects the Canadian taxes attributable to our share
of PAA's earnings related to their Canadian operations. For U.S. federal income
tax purposes, we utilize net operating loss carryforwards, or NOLs, to reduce
our currently payable taxes. As a result, we receive a deduction rather than a
credit for Canadian income taxes.
Current income tax expense for the first quarter of 2002 includes a benefit
of approximately $2.9 million representing tax paid in 2001 that was refunded to
us as the result of certain legislation that allowed us to offset 100% of
alternative minimum taxable income with NOLs. Previously, we could only offset
90% of AMT income with NOLs. The current income tax benefit is offset by a
corresponding charge to deferred income tax expense. This change in the
regulations did not change our overall effective tax rate and had no effect on
net income.
Cumulative effect of accounting change. In the first quarter of 2003 we
recognized a $0.9 million net of tax gain related to the adoption of Statement
of Accounting Standards, or SFAS, No. 143, "Accounting for Asset Retirement
Obligations". See "Recent Accounting Pronouncements" for a discussion of the
adoption of SFAS No. 143.
20
Income from discontinued operations. Income from discontinued operations of
$5.9 million in the first quarter of 2002 reflects the net after tax earnings of
PXP, which was spun off in the fourth quarter of 2002.
LIQUIDITY AND CAPITAL RESOURCES
GENERAL
At March 31, 2003 we had negative working capital of $13.9 million,
primarily reflecting $18.0 million of current maturities of long-term debt. Cash
generated from our upstream operations and PAA distributions are our primary
sources of liquidity. We believe that we have sufficient liquid assets and cash
from operations and PAA distributions to meet our short term and long-term
normal recurring operating needs, debt service obligations, contingencies and
anticipated capital expenditures.
If PAA could not, for any reason, make its minimum quarterly distribution
payments on its limited partnership interests, this would impair our cash flows
and our ability to meet our short and long-term cash needs. In addition, this
would trigger our payment obligations under the value assurance agreements (for
a description of the value assurance agreements, see "-- Commitments and
Contingencies"), which would compound the negative impact on our cash flows and
our ability to meet our short and long-term cash needs. Thus, PAA's financial
and operational performance directly affects our financial and operational
performance. We encourage you to review PAA's SEC filings, including its Annual
Report on Form 10-K for the year ended December 31, 2002 and its Quarterly
Report on Form 10-Q for the quarter ended March 31, 2003.
PAA CASH DISTRIBUTIONS
PAA's partnership agreement requires that it distribute 100% of available
cash within 45 days after the end of each quarter to unitholders of record and
to its general partner. Available cash is generally defined as all cash and cash
equivalents on hand at the end of each quarter less reserves established by
PAA's general partner for future requirements.
Distributions to holders of subordinated units are subject to the rights of
holders of common units to receive the minimum quarterly distribution, or MQD,
of $0.45 per unit ($1.80 per unit on an annual basis). Common units accrue
arrearages with respect to distributions for any quarter during the
subordination period and subordinated units do not accrue any arrearages. The
subordination period will end if PAA meets certain financial tests for three
consecutive four-quarter periods. If PAA meets certain financial requirements,
25% of the subordinated units will convert in the fourth quarter of 2003 and the
remainder will convert in the first quarter of 2004.
Class B common units are initially pari passu with common units with respect
to distributions, and are convertible into common units upon approval of a
majority of the common unitholders. If we request that PAA call a meeting of
common unitholders to consider approval of the conversion of Class B units into
common units and the approval is not obtained within 120 days, each Class B
common unitholder will be entitled to receive distributions, on a per unit
basis, equal to 110% of the amount of distributions paid on a common unit, with
such distribution right increasing to 115% if such approval is not secured
within 90 days after the end of the 120-day period. Except for the vote to
approve the conversion, Class B common units have the same voting rights as the
common units.
PAA's general partner is entitled to receive incentive distributions if the
amount distributed with respect to any quarter exceeds levels specified in its
partnership agreement. Generally the general partner is entitled, without
duplication, to 15% of amounts PAA distributes in excess of $0.450 per unit, 25%
of the amounts PAA distributes in excess of $0.495 per unit and 50% of amounts
PAA distributes in excess of $0.675 per unit.
Based on PAA's recently announced distribution of $0.55 per unit (an annual
distribution rate of $2.20 per unit), which will be paid in May 2003, we would
receive an annual distribution from PAA of approximately $31.2 million,
including $3.3 million for our general partner distribution (including $2.2
million for the general partner incentive distribution).
21
Cash distributions per unit on PAA's outstanding common units, Class B
common units and subordinated units and the portion of the distributions
representing an excess over the MQD in 2003, 2002 and 2001 were as follows:
YEAR
-----------------------------------------------------------------------------------------------
2003 2002 2001
------------------------------ ------------------------------ ------------------------------
EXCESS EXCESS EXCESS
DISTRIBUTION OVER MQD DISTRIBUTION OVER MQD DISTRIBUTION OVER MQD
-------------- -------------- -------------- ------------- -------------- --------------
First Quarter $ 0.5375 $ 0.0875 $ 0.5250 $ 0.0750 $ 0.4750 $ 0.0250
Second Quarter $ 0.5500 $ 0.1000 $ 0.5375 $ 0.0875 $ 0.5000 $ 0.0500
Third Quarter $ 0.5375 $ 0.0875 $ 0.5125 $ 0.0625
Fourth Quarter $ 0.5375 $ 0.0875 $ 0.5125 $ 0.0625
FINANCING ACTIVITIES
In December 2002 we entered into a $45 million secured term loan facility
with a group of banks. We used proceeds from the term loan and cash on hand to
make a $40 million capital contribution and repay a $7.2 million note payable to
PXP. The term loan is repayable in 10 quarterly installments of $4.5 million
each, commencing on February 28, 2003 with a final maturity of May 31, 2005.
Amounts outstanding under the term loan bear an annual interest rate, at our
election, equal to either the Base Rate (as defined in the agreement) plus 1.5%,
or LIBOR plus 3%. The term loan requires that we maintain $5.0 million on
deposit in a debt service reserve account with one of the lending banks. Our
average borrowing rate for the first quarter of 2003 was 4.7% (4.4% at March 31,
2003).
To secure the term loan, we pledged 100% of the shares of stock of our
subsidiaries and pledged 4,950,000 of our PAA common units. To the extent the
outstanding principal under the term loan exceeds the balance in the debt
service reserve account plus 50% of the fair market value of the pledged common
units, we are required to repay the excess. The fair market value of the pledged
units is determined based on the closing price of PAA common units as reported
on the New York Stock Exchange.
The term loan contains covenants that limit our ability, as well as the
ability of our subsidiaries, to incur additional debt, make investments, create
liens, enter into leases, sell assets, change the nature of our business or
operations, guarantee other indebtedness, enter into certain types of hedge
agreements, enter into take-or-pay arrangements, merge or consolidate and enter
into transactions with affiliates. In addition, if an event of default exists,
the term loan prohibits us from paying dividends or repurchasing or redeeming
shares of any class of capital stock. The term loan requires us to maintain a
minimum consolidated tangible net worth ($82.7 million at March 31, 2003) and a
consolidated debt service coverage ratio (as defined in the agreement) of 1.0 to
1.0.
THREE MONTHS ENDED
MARCH 31,
------------------------
2003 2002
---------- ----------
(IN MILLIONS)
Cash provided by (used in):
Operating activities $ 6.4 $ (5.9)
Investing activities (1.1) (0.6)
Financing activities (6.0) 20.8
CASH FLOWS FROM CONTINUING OPERATIONS
Operating Activities. Net cash provided by operating activities in the first
quarter of 2003 totaled $6.4 million compared to a $5.9 million use of cash in
the first quarter of 2003. The use of cash in 2002 primarily reflects a $13.6
million increase in working capital (excluding cash) during the period.
Investing Activities. In the first quarter of 2003 net cash used in
investing activities totaled $1.1 million compared to $0.6 million in the first
quarter of 2002. In the first quarter of 2003 we made capital contributions to
PAA of $0.6 million to maintain our proportionate general partner share interest
as a result of an equity offering by PAA.
22
Financing activities. Cash used in financing activities in the first quarter
of 2003 included a net reduction in long-term debt of $4.5 million, $0.6 million
in proceeds from issuances of our common stock, expenditures of $1.7 million for
the repurchase of 142,700 shares of our common stock, $0.1 million for the
payment of costs incurred in connection with our term loan and $0.3 million for
the payment of preferred stock dividends. Cash used in financing activities in
the first quarter of 2002 included a net increase in long-term debt of $19.5
million, $1.6 million in proceeds from issuances of our common stock and $0.3
million for the payment of preferred stock dividends.
CAPITAL EXPENDITURES
We have made and will continue to make capital expenditures with respect to
our oil properties. In the first quarter of 2003 we made aggregate capital
expenditures of $0.5 million for exploitation of our existing properties and
expect such expenditures to total $3.5 to $4.0 million in 2003.
When PAA issues equity, the general partner is required to contribute cash
to maintain its 2% general partner interest. In March 2003, PAA issued 2.6
million shares in a public equity offering. We were required to make a cash
capital contribution to the general partner of PAA in the amount of $0.6 million
for our 44% interest in the general partner. If PAA issues equity in the future,
we will be required to make additional cash capital contributions.
We also have an active treasury share repurchase program. Our Board of
Directors has authorized the repurchase of up to eight million shares of our
common stock. Through December 31, 2001, we had repurchased a total of 4.1
million shares at a total cost of approximately $91.3 million. No shares were
repurchased in 2002. We have resumed making purchases under the treasury share
program and through April 30, 2003 we have repurchased an additional 542,700
shares at a total cost of $5.6 million. We intend to make additional repurchases
in 2003 and expect to fund the purchases from cash flows.
CONTRACTUAL OBLIGATIONS
2003 2004 2005 2006 2007 THEREAFTER
------- ------- ------ ---------- ---------- ----------
Long-term debt $13,500 $18,000 $9,000 $ -- $ -- $ --
Operating leases 17 23 23 6 -- --
------- ------- ------ ---------- ---------- ----------
$13,517 $18,023 $9,023 $ 6 $ -- $ --
======= ======= ====== ========== ========== ==========
At March 31, 2003, the aggregate amounts of contractually obligated payment
commitments for the next five years are as follows (in thousands):
COMMITMENTS AND CONTINGENCIES
In connection with our June 2001 strategic restructuring, we entered into
value assurance agreements with the purchasers of the subordinated units in the
restructuring, under the terms of which we will pay the purchasers an amount per
fiscal year, payable on a quarterly basis, equal to $1.85 per unit less the
actual amount distributed during that year. The value assurance agreements will
expire upon the earlier of (a) the conversion of all of the subordinated units
to common units or (b) June 8, 2006. In the first quarter of 2003 PAA paid a
quarterly distribution of $0.5375 per unit ($2.15 annualized).
Also in connection with the June 2001 strategic restructuring, we entered
into a separation agreement with PAA whereby, among other things, (1) we agreed
to indemnify PAA, its general partner, and its subsidiaries against (a) any
claims related to the upstream business, whenever arising, and (b) any claims
related to federal or state securities laws or the regulations of any
self-regulatory authority, or other similar claims, resulting from alleged acts
or omissions by us, our subsidiaries, PAA, or PAA's subsidiaries occurring on or
before June 8, 2001, and (2) PAA agreed to indemnify us and our subsidiaries
against any claims related to the midstream business, whenever arising.
In connection with the reorganization and the spin-off we entered into
certain agreements with PXP, including a master separation agreement; an
intellectual property agreement; the Plains Exploration & Production transition
services agreement; the Plains Resources transition services agreement; and a
technical services agreement. The master separation agreement provides for
cross-indemnities intended to place sole financial responsibility on PXP for all
liabilities
23
associated with the current and historical businesses and operations PXP
conducts after giving effect to the spin off (and related reorganization),
regardless of the time those liabilities arise, and to place sole financial
responsibility for liabilities associated with our businesses with us and our
subsidiaries. We agree to indemnify PXP and PXP agreed to indemnify us against
liabilities arising from misstatements or omissions in the various offering
documents for the exchange offer related to PXP's 8.75% notes or the spin-off,
if such information was prepared by us or PXP, as the case may be.
In the ordinary course of business, we are a claimant and/or defendant in
various legal proceedings. In particular, we are a party to a lawsuit (as a
result of Stocker Resources, Inc.'s merger into us) regarding an electric
services contract with Commonwealth Energy Corporation. In this lawsuit, we are
seeking a declaratory judgment that we are entitled to terminate the contract
and that Commonwealth has no basis for proceeding against a related $1.5 million
performance bond. In a countersuit against us, Commonwealth is seeking
unspecified damages. The two cases have been consolidated and set for trial in
December 2003. We intend to defend our rights vigorously in this matter. Under
the spin-off agreements, PXP will indemnify us against this lawsuit. We do not
believe that the outcome of these legal proceedings, individually or in the
aggregate, will have a material adverse effect on our financial condition,
results of operations or cash flows.
PAA'S COMMITMENTS AND CONTINGENCIES
For a discussion of PAA's commitments and contingencies, we recommend you
review PAA's Annual Report on Form 10-K for the year ended December 31, 2002 and
its Quarterly Report on Form 10-Q for the quarter ended March 31, 2003, and
other applicable SEC filings by PAA.
RELATED PARTY TRANSACTIONS
GOVERNANCE OF PAA
We, along with Sable Investments, L.P. (which is owned by Mr. Flores, our
Chairman, and Mr. Raymond, our Chief Executive Officer and President), Kafu
Holdings, L.P. (which is controlled by Kayne Anderson Capital Advisors, L.P. and
Kayne Anderson Investment Management, Inc., of which Mr. Sinnott, our director,
is Senior Vice President), and E-Holdings III, L.P. (which is controlled by
EnCap Investments L.L.C. and of which Mr. Phillips, our director, is a managing
director and principal) are parties to agreements governing Plains All American
GP LLC, which is the general partner of Plains AAP, L.P., and Plains AAP, L.P.,
which is the general partner of PAA. These agreements govern the ongoing
management of PAA.
In addition, the general partner of PAA is owned as follows:
Plains Resources 44.00%
Sable Investments, L.P. 20.00%
Kafu Holdings, L.P. 16.42%
E-Holdings, L.P. 9.00%
Others 10.58%
------
100.00%
======
Also, each of we, Sable Investments, Kafu Holdings, and E-Holdings may
appoint one member of the Plains All American GP LLC board of directors.
VALUE ASSURANCE AGREEMENTS
We entered into a value assurance agreement with each of Sable Investments,
Kafu Holdings and E-Holdings with respect to the subordinated units they
acquired from us in our June 2001 strategic restructuring. The value assurance
agreements require us to pay to them an amount per fiscal year, payable on a
quarterly basis, equal to the difference between $1.85 per unit and the actual
amount distributed during that period. The value assurance agreements will
expire upon the earlier of the conversion of the subordinated units to common
units, or June 8, 2006.
24
OUR RELATIONSHIP WITH PAA
We have ongoing relationships with PAA, including:
- a marketing agreement that provides that PAA will purchase all of our
equity oil production at market prices for a fee of $.20 per barrel.
In the first quarter of 2003, PAA paid us $8.6 million for such equity
production and we paid PAA $47,000 in marketing fees; and
- a separation agreement whereby, among other things, (1) we agreed to
indemnify PAA, its general partner, and its subsidiaries against (a)
any claims related to the upstream business, whenever arising, and (b)
any claims related to federal or state securities laws or the
regulations of any self-regulatory authority, or other similar claims,
resulting from alleged acts or omissions by us, our subsidiaries, PAA,
or PAA's subsidiaries occurring on or before June 8, 2001, and (2) PAA
agreed to indemnify us and our subsidiaries against any claims related
to the midstream business, whenever arising.
We are currently negotiating a new marketing agreement with PAA to, among
other things, add a definitive term to the agreement and provide that PAA will
use its reasonable best efforts to obtain the best price for our oil production.
There can be no assurance, however, that we will enter into a new marketing
agreement with PAA.
SPIN-OFF AGREEMENTS
In connection with the reorganization and the spin-off we entered into
certain agreements with PXP, including a master separation agreement; an
intellectual property agreement; the Plains Exploration & Production transition
services agreement; the Plains Resources transition services agreement; and a
technical services agreement. For the three months ended March 31, 2003 PXP
billed us $136,000 for services provided to us under these agreements and we
billed PXP $38,000 for services we provided under these agreements.
The master separation agreement provides that for a period of three years,
(1) we and our subsidiaries will be prohibited from engaging in or acquiring any
business engaged in any of the "upstream" activities of acquiring, exploiting,
developing, exploring for and producing oil and gas in any state in the United
States (except Florida), and (2) PXP will be prohibited from engaging in any of
the "midstream" activities of marketing, gathering, transporting, terminalling
and storing oil and gas (except to the extent any such activities are ancillary
to, or in support of, any of PXP's upstream activities(.
CRITICAL ACCOUNTING POLICIES AND FACTORS THAT MAY AFFECT FUTURE RESULTS
Based on the accounting policies which we have in place, certain factors may
impact our future financial results. The most significant of these factors and
their effect on certain of our accounting policies are discussed below.
Commodity pricing and risk management activities. Prices for oil have
historically been volatile. Decreases in oil prices from current levels will
adversely affect our revenues, results of operations, cash flows and proved
reserves. If the industry experiences significant prolonged future price
decreases, this could be materially adverse to our operations and our ability to
fund planned capital expenditures.
Periodically, we enter into hedging arrangements relating to a portion of
our oil production to achieve a more predictable cash flow, as well as to reduce
our exposure to adverse price fluctuations. Hedging instruments used are
typically fixed price swaps and collars and purchased puts and calls. While the
use of these types of hedging instruments limits our downside risk to adverse
price movements, we are subject to a number of risks, including instances in
which the benefit to revenues is limited when commodity prices increase. Since
we were required to discontinue hedge accounting effective February 1, 2003 and
reflect the mark-to-market value of our hedges in earnings, absent a stable oil
price environment, the potential gains or losses related to SFAS 133 are likely
to materially change reported net income and increase the volatility of reported
net income due to non-cash mark-to-market gains or losses. For a further
discussion concerning our risks related to oil prices and our hedging programs,
see "-- Quantitative and Qualitative Disclosures about Market Risks".
25
Write-downs under full cost ceiling test rules. Under the SEC's full cost
accounting rules we review the carrying value of our proved oil and gas
properties each quarter. Under these rules, capitalized costs of proved oil and
gas properties (net of accumulated depreciation, depletion and amortization, and
deferred income taxes) may not exceed a "ceiling" equal to: the standardized
measure (including, for this test only, the effect of any related hedging
activities); plus the lower of cost or fair value of unproved properties not
included in the costs being amortized (net of related tax effects).
These rules generally require that we price our future oil production at the
prices in effect at the end of each fiscal quarter and require a write-down if
our capitalized costs exceed this "ceiling," even if prices declined for only a
short period of time. We have had no write-downs due to these ceiling test
limitations since 1998. Given the volatility of oil prices, it is likely that
our estimate of discounted future net revenues from proved oil reserves will
change in the near term. If oil prices decline in the future, even if only for a
short period of time, write-downs of our oil and gas properties could occur.
Write-downs required by these rules do not directly impact our cash flows from
operating activities.
Based on the book value of our proved oil and gas properties (including
related deferred income taxes) and our estimated proved reserves as of March 31,
2003, we believe that we would have a write-down under the full cost ceiling
test rules at a net realized price for our oil production of approximately
$16.35 per barrel. Based on an estimated oil differential for 2003 plus oil
transportation of $12.25 - $12.75 per barrel, we would have a write-down at a
NYMEX crude oil index price of $28.60 - $29.10 per barrel.
Oil and gas reserves. Our proved reserves are based on estimates prepared by
outside engineering firms. Estimates prepared by others may be higher or lower
than these estimates.
Estimates of proved reserves may be different from the actual quantities of
oil and gas recovered because such estimates depend on many assumptions and are
based on operating conditions and results at the time the estimate is made. The
actual results of drilling and testing, as well as changes in production rates
and recovery factors, can vary significantly from those assumed in the
preparation of reserve estimates. As a result, such factors have historically,
and can in the future, cause significant upward and downward revisions to proved
reserve estimates.
You should not assume that the present value of future net cash flows is the
current market value of our estimated proved oil and gas reserves. In accordance
with SEC requirements, we base the estimated discounted future net revenues from
proved reserves on prices and costs on the date of the estimate. Actual future
prices and costs may be materially higher or lower than the prices and costs as
of the date of the estimate.
All of our reserve base is comprised of oil properties that are sensitive to
oil price volatility. Historically, we have experienced significant upward and
downward revisions to our reserves volumes and values as a result of changes in
year-end oil and gas prices and the corresponding adjustment to the projected
economic life of such properties. Prices for oil and gas are likely to continue
to be volatile, resulting in future downward and upward revisions to our reserve
base.
Our rate for recording DD&A expense is dependent upon our estimate of proved
reserves including future development and abandonment costs as well as our level
of capital spending. If the estimates of proved reserves decline, the rate at
which we record DD&A expense increases, reducing our net income. This decline
may result from lower market prices, which may make it uneconomic to drill for
and produce higher cost fields. The decline in proved reserve estimates may
impact the outcome of the "ceiling" test discussed above. In addition, increases
in costs required to develop our reserves would increase the rate at which we
record DD&A expense. We are unable to predict changes in future development
costs as such costs are dependent on the success of our exploitation and
development program, as well as future economic conditions.
PAA's Critical Accounting Policies. For a discussion of PAA's critical
accounting policies, we recommend you review PAA's Annual Report on Form 10-K
for the year ended December 31, 2002 and Quarterly Report on Form 10-Q for the
quarter ended March 31, 2003, and other applicable SEC filings by PAA.
ADOPTION OF SFAS NO. 143
We adopted SFAS No. 143, "Accounting for Asset Retirement Obligations"
effective January 1, 2003. SFAS No. 143 requires entities to record the fair
value of a liability for an asset retirement obligation in the period in which
it is incurred and a corresponding increase in the carrying amount of the
related long-lived asset. Each period the liability is accreted to
26
its then present value, and the capitalized cost is depreciated over the useful
life of the related asset. If the liability is settled for an amount other than
the recorded amount, a gain or loss is recognized. In prior periods we included
estimated future costs of abandonment and dismantlement in our full cost
amortization base and these costs were amortized as a component of our depletion
expense.
At January 1, 2003 the present value of our future Asset Retirement
Obligation for oil and gas properties and equipment was $2.6 million. The
cumulative effect of our adoption of SFAS No. 143 and the change in accounting
principle resulted in an increase in income during the first quarter of 2003 of
$0.9 million (reflecting a $2.8 million decrease in accumulated DD&A, partially
offset by $1.3 million in accretion expense, and $0.6 million deferred income
tax expense). We recorded a liability of $2.6 million and an asset of $1.2
million in connection with the adoption of SFAS 143. There will be no impact on
our cash flows as a result of adopting SFAS No. 143.
RECENT ACCOUNTING PRONOUNCEMENTS
The Financial Accounting Standards Board issued SFAS No. 149 "Amendment of
Statement 133 on Derivative Instruments and Hedging Activities" on April 30,
2003. The statement is effective for contracts entered into or modified after
June 30, 2003 and for hedging relationships designated after June 30, 2003. At
this time, we cannot reasonably estimate the effect of the adoption of SFAS No.
149 on either our financial position or results of operations
STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q includes forward-looking statements based
on our current expectations and projections about future events. Statements that
are predictive in nature, that depend upon or refer to future events or
conditions, or that include words such as "will", "would", "should", "plans",
"likely", "expects", "anticipates", "intends", "believes", "estimates",
"thinks", "may", and similar expressions, are forward-looking statements. These
statements involve known and unknown risks, uncertainties, and other factors
that may cause our actual results and performance to be materially different
from any future results or performance expressed or implied by these
forward-looking statements. These factors include, among other things:
- the consequences of any potential change in the relationship between
us and PXP;
- the consequences of our and PXP's officers and employees providing
services to both us and PXP and not being required to spend any
specified percentage or amount of time on our business;
- risks, uncertainties and other factors that could have an impact on
PAA which could in turn impact the value of our holdings in PAA (for a
discussion of these risks, uncertainties and other factors, see PAA's
filings with the SEC);
- the effects of our indebtedness, which could adversely restrict our
ability to operate, could make us vulnerable to general adverse
economic and industry conditions, could place us at a competitive
disadvantage compared to our competitors that have less debt, and
could have other adverse consequences;
- uncertainties inherent in the development and production of oil and
gas and in estimating reserves;
- unexpected future capital expenditures (including the amount and
nature thereof);
- impact of oil and gas price fluctuations;
- the effects of competition;
- the success of our risk management activities;
- the availability (or lack thereof) of acquisition or combination
opportunities;
- the impact of current and future laws and governmental regulations;
- environmental liabilities that are not covered by an effective
indemnity or insurance, and
- general economic, market, industry or business conditions.
All forward-looking statements in this report are made as of the date
hereof, and you should not place undue certainty on these statements without
also considering the risks and uncertainties associated with these statements
and our business that are discussed in this report. Moreover, although we
believe the expectations reflected in the forward-looking statements are based
upon reasonable assumptions, we can give no assurance that we will attain these
expectations or
27
that any deviations will not be material. Except as required by applicable
securities laws, we do not intend to update these forward-looking statements and
information. See "Critical Accounting Policies and Factors That May Affect
Future Results" in this report for additional discussions of risks and
uncertainties.
28
ITEM 3. - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
We are exposed to various market risks, including volatility in oil
commodity prices and interest rates. To manage our exposure, we monitor current
economic conditions and our expectations of future commodity prices and interest
rates when making decisions with respect to risk management. We do not enter
into derivative transactions for speculative trading purposes.
We utilize various derivative instruments to hedge our exposure to price
fluctuations on oil sales. The derivative instruments consist primarily of
cash-settled oil option and swap contracts entered into with financial
institutions. Derivative instruments are accounted for in accordance with SFAS
No. 133 "Accounting for Derivative Instruments and Hedging Activities" as
amended by SFAS 137 and SFAS 138, or SFAS 133. All derivative instruments are
recorded on the balance sheet at fair value. If the derivative does not qualify
as a hedge or is not designated as a hedge, the gain or loss on the derivative
is recognized currently in earnings. To qualify for hedge accounting, the
derivative must qualify either as a fair value hedge, cash flow hedge or foreign
currency hedge. Currently, we use only cash flow hedges and the remaining
discussion will relate exclusively to this type of derivative instrument. If the
derivative qualifies for hedge accounting, the gain or loss on the derivative is
deferred in accumulated Other Comprehensive Income, or OCI, a component of our
stockholders' equity, to the extent the hedge is effective.
We formally document all relationships between hedging instruments and
hedged items, as well as our risk management objectives and strategy for
undertaking the hedge. Hedge effectiveness is measured at least on a quarterly
basis. This process includes specific identification of the hedging instrument
and the hedged item, the nature of the risk being hedged and how the hedging
instrument's effectiveness will be assessed. The relationship between the
hedging instrument and the hedged item must be highly effective in achieving the
offset of changes in cash flows attributable to the hedged risk both at the
inception of the contract and on an ongoing basis. Hedge accounting is
discontinued prospectively when a hedge instrument becomes ineffective. Gains
and losses deferred in OCI related to cash flow hedges that become ineffective
remain unchanged until the related product is delivered. If it is determined
that it is probable that a hedged forecasted transaction will not occur,
deferred gains or losses on the hedging instrument are recognized in earnings
immediately.
In the first quarter of 2003, the NYMEX oil price and the price we receive
for our Florida oil production did not correlate closely enough for the hedges
to qualify for hedge accounting. As a result, we were required to discontinue
hedge accounting effective February 1, 2003 and reflect the mark-to-market value
of the hedges in earnings prospectively from that date. In the two months ended
March 31, 2003 we recorded a $0.7 million gain for the increase in the fair
value of our derivatives and recognized a $0.7 million loss on cash settlements
of such derivatives. Cash settlements of $0.3 million for January 2003 are
reflected as a reduction of revenues.
At March 31, 2003accumulated OCI consisted of unrealized losses of $1.5
million ($0.7 million, net of tax) on our oil hedging instruments, $0.5 million
($0.3 million, net of tax) related to pension liabilities and an unrealized gain
of $1.3 million ($0.6 million, net of tax) related to our equity in the OCI
gains of PAA. At March 31, 2003, the liability related to our open oil hedging
instruments was included in current liabilities ($1.3 million), other long-term
liabilities ($0.1 million), and deferred income taxes (a tax benefit of $0.7
million)
During the first quarter of 2002 oil sales revenues were reduced by $0.1
million for non-cash expense related to the amortization of option premiums. As
of March 31, 2003, $1.3 million ($0.7 million, net of tax) of deferred net
losses on our oil hedging instruments recorded in OCI are expected to be
reclassified to earnings during the following twelve months.
Commodity Price Risk. At April 30, 2003, we had the following open oil
derivative positions:
BARRELS PER DAY
------------------
2003 2004
----- ------
Swaps
Average price $26.10/bbl 1,500 --
Average price $24.07/bbl -- 1,000
29
Assuming our first quarter 2003 production volumes are held constant in
subsequent periods, these positions represent approximately 58% and 39% of oil
production in 2003 and 2004, respectively. Location and quality differentials
attributable to our properties are not included in the foregoing prices. Because
of the quality and location of our oil production, these adjustments will reduce
our net realized price per barrel.
The agreements provide for monthly cash settlement based on the differential
between the agreement price and the actual NYMEX price. For periods prior to
February 1, 2003 gains or losses were recognized in the month of related
production and were included in oil sales revenues. Such contracts resulted in a
reduction of revenues of $0.3 million and $0.1 million in the first quarter of
2003 and 2002, respectively.
The fair value of outstanding oil derivative commodity instruments and the
change in fair value that would be expected from a 10 percent price decrease are
shown in the table below (in millions):
MARCH 31, 2003 DECEMBER 31, 2002
----------------------------------- -----------------------------------
EFFECT OF EFFECT OF
10% 10%
FAIR PRICE FAIR PRICE
VALUE DECREASE VALUE DECREASE
----------- -------------- -------------- -------------
Swaps and options contracts $ (0.8) $ 2.0 $ (0.4) $ 1.9
The fair value of the swaps and option contracts are estimated based on
quoted prices from independent reporting services compared to the contract price
of the swap and approximate the gain or loss that would have been realized if
the contracts had been closed out at year end. All such positions offset
physical positions exposed to the cash market. None of these offsetting physical
positions are included in the above table. Price-risk sensitivities were
calculated by assuming an across-the-board 10 percent decrease in price
regardless of term or historical relationships between the contractual price of
the instruments and the underlying commodity price. In the event of an actual 10
percent change in prompt month oil prices, the fair value of our derivative
portfolio would typically change less than that shown in the table due to lower
volatility in out-month prices.
Our management intends to continue to maintain derivative arrangements for a
significant portion of our production. These contracts may expose us to the risk
of financial loss in certain circumstances. Such arrangements provide us
protection if oil prices decline below the prices at which the derivatives are
set, but ceiling prices in our derivatives may cause us to receive less revenue
on the specified volumes than we would receive in the absence of the
derivatives. Such arrangements may or may not qualify for hedge accounting. The
contract counterparties for our current derivative commodity contracts are all
major financial institutions with Standard & Poor's ratings of A or better.
Interest Rate Risk. Our debt instruments are sensitive to market
fluctuations in interest rates. At March 31, 2003 we had $40.5 million
outstanding under our term loan, repayable $13.5 million in 2003, $18.0 million
in 2004 and $9.0 million in 2005. Our term loan bears interest at a base rate
(as defined) or LIBOR plus 3%. The carrying value of our term loan approximates
fair value because interest rates are variable, based on prevailing market
rates.
30
ITEM 4. - CONTROLS AND PROCEDURES
Within 90 days before the date of this report on Form 10-Q, under the
supervision and with the participation of our management, including our Chief
Executive Officer (our principal executive officer) and our Chief Financial
Officer (our principal financial officer), we evaluated the effectiveness of our
disclosure controls and procedures (as defined under Rule 13a-14(c) of the
Securities Exchange Act of 1934, as amended (the "Exchange Act")). Based on this
evaluation, our Chief Executive Officer and our Chief Financial Officer
concluded that our disclosure controls and procedures are effective to ensure
that information we are required to disclose in the reports that we file or
submit under the Exchange Act is recorded, processed, summarized and reported
within the time periods specified in the SEC's rules and forms.
There were no significant changes in our internal controls or in other
factors that could significantly affect these controls subsequent to the date of
such evaluation.
31
PART II. OTHER INFORMATION
ITEM 1 - LEGAL PROCEEDINGS.
We, in the ordinary course of business, are a claimant and/or defendant in
various legal proceedings. We do not believe that the outcome of these legal
proceedings, individually and in the aggregate, will have a materially adverse
effect on our financial condition, results of operations or cash flows.
We are a party to a lawsuit (as a result of Stocker Resources, Inc.'s merger
into us) regarding an electric services contract with Commonwealth Energy
Corporation. In this lawsuit, we are seeking a declaratory judgment that we are
entitled to terminate the contract and that Commonwealth has no basis for
proceeding against a related $1.5 million performance bond. In a countersuit
against us, Commonwealth is seeking unspecified damages. The two cases have been
consolidated and set for trial in December 2003. We intend to defend our rights
vigorously in this matter. Under the spin-off agreements, PXP will indemnify us
against this lawsuit. We do not believe that the outcome of these legal
proceedings, individually or in the aggregate, will have a material adverse
effect on our financial condition, results of operations or cash flows.
ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
99.1 Chief Executive Officer Certification Pursuant to 18 U.S.C Section
1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002
99.2 Chief Financial Officer Certification Pursuant to 18 U.S.C Section
1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002
(b) Reports on Form 8-K
A Current Report on Form 8-K was filed on May 2, 2003 with respect to the
Company's press release reporting earnings for the first quarter of 2003 and
current estimates of certain results for 2003.
A Current Report on Form 8-K was filed on February 27, 2003 with respect to
the Company's press release reporting 2002 earnings and December 31, 2002 oil
and gas reserve information.
A Current Report on Form 8-K was filed on February 27, 2003 with respect to
current estimates of certain results for 2003.
A Current Report on Form 8-K was filed on January 2, 2003 with respect to
the completion of the spin off and the Company's new term loan facility.
ITEMS 2, 3, 4 & 5 ARE NOT APPLICABLE AND HAVE BEEN OMITTED
32
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: May 9, 2003 By: /s/ Stephen A. Thorington
----------------------------------------------------
Stephen A. Thorington
Executive Vice President and Chief Financial Officer
(Principal Financial and Accounting Officer)
33
CERTIFICATION
I, John T. Raymond, Chief Executive Officer and President of Plains Resources
Inc., certify that:
1. I have reviewed this quarterly report on Form 10-Q of Plains Resources
Inc.;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a. designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this quarterly report is being
prepared;
b. evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c. presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit committee
of registrant's board of directors (or persons performing the equivalent
function):
a. all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b. any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls;
and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
/s/ John T. Raymond
--------------------------------------------
Name: John T. Raymond
Title: Chief Executive Officer and President
Date: May 9, 2003
34
CERTIFICATION
I, Stephen A. Thorington, Chief Financial Officer and Executive Vice President
of Plains Resources Inc., certify that:
1. I have reviewed this quarterly report on Form 10-Q of Plains Resources
Inc.;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and wehave:
a. designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this quarterly report is being
prepared;
b. evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c. presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit committee
of registrant's board of directors (or persons performing the equivalent
function):
a. all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b. any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls;
and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
/s/ Stephen A. Thorington
--------------------------------------------
Name: Stephen A. Thorington
Title: Chief Financial Officer and Executive
Vice President
Date: May 9, 2003
35
EXHIBIT INDEX
Exhibits Description of Exhibit
99.1 Chief Executive Officer Certification Pursuant to 18 U.S.C Section
1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002
99.2 Chief Financial Officer Certification Pursuant to 18 U.S.C Section
1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002