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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 JUNE 30, 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 [ ]
23.6 million shares of common stock, $0.10 par value, issued and
outstanding at July 31, 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)
June 30, 2003 and December 31, 2002.............................................................................. 3
Consolidated Statements of Income (Unaudited)
For the three months and six months ended June 30, 2003 and 2002................................................. 4
Consolidated Statements of Cash Flows (Unaudited)
For the six months ended June 30, 2003 and 2002.................................................................. 5
Consolidated Statements of Comprehensive Income (Unaudited)
For the six months ended June 30, 2003 and 2002.................................................................. 6
Consolidated Statements of Changes in Stockholders' Equity (Unaudited)
For the six months ended June 30, 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)
JUNE 30, DECEMBER 31,
2003 2002
--------------- ---------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 1,778 $ 8,807
Accounts receivable - Plains All American
Pipeline, L.P. 2,938 -
Other accounts receivable 41 1,589
Inventory 1,788 2,305
Other current assets 1,645 1,515
--------------- --------------
8,190 14,216
--------------- --------------
PROPERTY AND EQUIPMENT, AT COST
Oil and gas properties - full cost method
Subject to amortization 352,062 349,517
Other property and equipment 27 27
--------------- --------------
352,089 349,544
Less allowance for depreciation,
depletion and amortization (298,403) (299,214)
--------------- --------------
53,686 50,330
--------------- --------------
INVESTMENT IN PLAINS ALL AMERICAN PIPELINE, L.P. 82,202 70,042
--------------- --------------
OTHER ASSETS
Deferred income taxes 8,460 16,957
Other 10,294 9,867
--------------- --------------
18,754 26,824
--------------- --------------
$ 162,832 $ 161,412
=============== ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable $ 1,327 $ 1,361
Taxes payable 2,881 1,878
Current maturities of long-term debt 20,000 18,000
Other current liabilities 5,161 4,948
--------------- --------------
29,369 26,187
--------------- --------------
LONG-TERM BANK DEBT 40,000 27,000
--------------- --------------
ASSET RETIREMENT OBLIGATION 1,957 -
--------------- --------------
OTHER LONG-TERM LIABILITIES 2,937 2,716
--------------- --------------
STOCKHOLDERS' EQUITY
Series D cumulative convertible preferred stock - 23,300
Common stock 2,823 2,806
Additional paid-in capital 275,781 273,162
Retained earnings (deficit) (96,066) (103,882)
Accumulated other comprehensive income 2,023 (2,862)
Treasury stock, at cost (95,992) (87,015)
--------------- --------------
88,569 105,509
--------------- --------------
$ 162,832 $ 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 SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------------ ----------------------------
REVENUES 2003 2002 2003 2002
-------------- ------------ ------------- ------------
Oil sales to Plains All American
Pipeline, L.P. $ 4,347 $ 4,787 $ 11,624 $ 8,966
Hedging - (128) (307) (251)
-------------- ------------ -------------
4,347 4,659 11,317 8,715
-------------- ------------ ------------- ------------
COSTS AND EXPENSES
Production expenses 1,520 1,304 3,378 2,697
Production and ad valorem taxes 233 125 637 228
Oil transportation expenses 910 891 2,028 1,830
General and administrative 1,595 1,708 3,407 3,375
Depreciation, depletion and amortization 1,028 1,168 2,433 2,327
Accretion of asset retirement obligation 57 - 113 -
Other operating expenses 137 - 137 -
-------------- ------------ ------------- ------------
5,480 5,196 12,133 10,457
-------------- ------------ ------------- ------------
OTHER INCOME (EXPENSE)
Equity in earnings of Plains All American Pipeline, L.P. 5,397 5,256 11,722 9,606
Gain on Plains All American Pipeline, L.P. unit offering - - 6,108 -
Gain (loss) on derivatives
Change in fair value (1,299) - (633) -
Cash settlements (382) - (1,114) -
Interest expense (508) (1,790) (1,009) (3,477)
Interest and other income 31 8 106 27
-------------- ------------ ------------- ------------
3,239 3,474 15,180 6,156
-------------- ------------ ------------- ------------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 2,106 2,937 14,364 4,414
Income tax benefit (expense)
Current (210) (363) (2,601) 2,405
Deferred (800) (1,118) (4,276) (4,631)
-------------- ------------ ------------- ------------
INCOME FROM CONTINUING OPERATIONS 1,096 1,456 7,487 2,188
Income from discontinued operations, net of tax - 8,218 - 14,082
-------------- ------------ ------------- ------------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE 1,096 9,674 7,487 16,270
Cumulative effect of accounting change, net of tax - - 933 -
-------------- ------------ ------------- ------------
NET INCOME 1,096 9,674 8,420 16,270
Preferred dividends (253) (350) (603) (700)
-------------- ------------ ------------- ------------
INCOME AVAILABLE TO COMMON STOCKHOLDERS $ 843 $ 9,324 $ 7,817 $ 15,570
============== ============ ============= ============
EARNINGS PER SHARE (IN DOLLARS)
Basic
Income from continuing operations $ 0.04 $ 0.05 $ 0.29 $ 0.06
Discontinued operations - 0.34 - 0.60
Change in accounting policy - - 0.04 -
-------------- ------------ ------------- ------------
$ 0.04 $ 0.39 $ 0.33 $ 0.66
============== ============ ============= ============
Diluted
Income from continuing operations $ 0.04 $ 0.04 $ 0.28 $ 0.06
Discontinued operations - 0.33 - 0.58
Change in accounting policy - - 0.04 -
-------------- ------------ ------------- ------------
$ 0.04 $ 0.37 $ 0.32 $ 0.64
============== ============ ============= ============
Weighted average shares outstanding
Basic 23,475 23,883 23,727 23,759
Diluted 25,151 24,585 24,172 24,373
See notes to consolidated financial statements.
4
PLAINS RESOURCES INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(IN THOUSANDS)
SIX MONTHS ENDED
JUNE 30,
-----------------------------
2003 2002
----------- ------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 8,420 $ 16,270
Items not affecting cash flows from continuing operating activities
Income from discontinued operations, net of tax - (14,082)
Depreciation, depletion and amortization 2,433 2,327
Accretion of asset retirement obligation 113 -
Equity in earnings of Plains All American Pipeline, L.P. (11,722) (9,606)
Gain on Plains All American Pipeline, L.P. unit offering (6,108) -
Distributions received from Plains All American Pipeline, L.P. 15,298 14,140
Deferred income taxes 4,276 4,631
Cumulative effect of adoption of SFAS 143, net of tax (933) -
Change in derivative fair value 633 -
Noncash compensation expense 1,307 -
Other noncash items 147 721
Change in assets and liabilities from operating activities (1,602) 2,768
----------- ------------
Net cash provided by (used in) continuing activities 12,262 17,169
Net cash provided by (used in) discontinued activities - 19,776
----------- ------------
Net cash provided by (used in) operating activities 12,262 36,945
----------- ------------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties (1,494) (4,720)
Additions to other property and equipment - (31)
Investment in Plains All American Pipeline, L.P. (589) -
----------- ------------
Net cash provided by (used in) continuing activities (2,083) (4,751)
Net cash provided by (used in) discontinued activities - (42,358)
----------- ------------
Net cash provided by (used in) investing activities (2,083) (47,109)
----------- ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Net change in credit facility 15,000 6,000
Proceeds from exercise of stock options 1,382 4,411
Retirement of Series D preferred stock (23,300) -
Treasury stock purchases (8,977) -
Costs incurred in connection with financing arrangements (710) -
Preferred stock dividends (603) (350)
----------- ------------
Net cash provided by (used in) continuing activities (17,208) 10,061
Net cash provided by (used in) discontinued activities - -
----------- ------------
Net cash provided by (used in) financing activities (17,208) 10,061
----------- ------------
Net increase (decrease) in cash and cash equivalents (7,029) (103)
Cash and cash equivalents, beginning of period 8,807 1,179
----------- ------------
Cash and cash equivalents, end of period $ 1,778 $ 1,076
=========== ============
See notes to consolidated financial statements
5
PLAINS RESOURCES INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
(IN THOUSANDS)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
-------------------------- ------------------------
2003 2002 2003 2002
------------ ------------ ----------- -----------
NET INCOME $ 1,096 $ 9,674 $ 8,420 $ 16,270
------------ ------------ ----------- -----------
OTHER COMPREHENSIVE INCOME (LOSS):
From continuing operations:
Commodity hedging contracts, net of tax:
Change in fair value - 145 (956) (597)
Reclassification adjustment for
settled contracts 317 - 785 (10)
Interest rate swap, net of tax - (105) - (75)
Equity in other comprehensive income
changes of Plains All American
Pipeline, L.P. , net of tax 2,082 2,451 5,056 2,004
------------ ------------ ----------- -----------
2,399 2,491 4,885 1,322
From discontinued operations - (1,861) - (25,039)
------------ ------------ ----------- -----------
2,399 630 4,885 (23,717)
------------ ------------ ----------- -----------
COMPREHENSIVE INCOME $ 3,495 $ $ 10,304 $ 13,305 $ (7,447)
============ ============ =========== ===========
See notes to consolidated financial statements.
6
PLAINS RESOURCES INC.
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY (UNAUDITED)
(IN THOUSANDS)
SIX MONTHS ENDED
JUNE 30, 2003
----------------------------------------------------------
SHARES AMOUNT
-------------------------- ------------------------------
SERIES D CUMULATIVE CONVERTIBLE PREFERRED STOCK
Balance, beginning of period 46,600 $ 23,300
Shares retired (46,600) (23,300)
-------------------------- ------------------------------
Balance, end of period - -
========================== ------------------------------
COMMON STOCK
Balance, beginning of period 28,048 2,806
Common stock issued upon exercise of
stock options and other 173 17
-------------------------- ------------------------------
Balance, end of period 28,221 2,823
========================== ------------------------------
ADDITIONAL PAID-IN CAPITAL
Balance, beginning of period 273,162
Common stock issued upon exercise of
stock options and other 2,619
------------------------------
Balance, end of period 275,781
------------------------------
RETAINED EARNINGS (DEFICIT)
Balance, beginning of period (103,882)
Net income 8,419
Preferred stock dividends (603)
------------------------------
Balance, end of period (96,066)
------------------------------
ACCUMULATED OTHER COMPREHENSIVE INCOME
Balance, beginning of period (2,862)
Other comprehensive income 4,885
------------------------------
Balance, end of period 2,023
------------------------------
TREASURY STOCK
Balance, beginning of period 3,854 (87,015)
Purchase of treasury shares 820 (8,977)
-------------------------- ------------------------------
Balance, end of period 4,674 (95,992)
========================== ------------------------------
TOTAL $ 88,569
==============================
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 June 30, 2003 and December 31, 2002, the
results of our operations for the three months and six months ended June 30,
2003 and 2002, our cash flows, comprehensive income and the changes in our
stockholders' equity for the six months ended June 30, 2003. The results for the
six months ended June 30, 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 8.
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 in 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. Adopting SFAS No. 143 does not effect our cash flows.
8
The following table illustrates the changes in our asset retirement
obligation during the period (in thousands):
SIX MONTHS ENDED JUNE 30,
----------------------------------
2003 2002
------------ ------------
Pro forma
Asset retirement obligation - beginning of period $ 2,556 $ 2,403
Accretion expense 113 107
Asset retirement costs incurred (174) -
------------ ------------
Asset retirement obligation - end of period $ 2,495(1) $ 2,510
============ ============
(1) $538 included in other current liabilities
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 and six months ended June 30, 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):
JUNE 30, DECEMBER 31,
2003 2002
--------- ---------
Oil $ 1,202 $ 1,482
Materials and supplies 586 823
--------- ---------
$ 1,788 2,305
========= =========
Other Assets. Other assets consists of the following (in thousands):
JUNE 30, DECEMBER 31,
2003 2002
--------- ---------
Restricted cash $ 5,027 $ 5,000
Debt issue costs, net 1,115 612
Receivable from PXP 3,202 3,202
Other 950 1,053
--------- ---------
$ 10,294 $ 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.
9
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 SIX MONTHS ENDED
---------------------------- ----------------------------
JUNE 30, JUNE 30,
---------------------------- ----------------------------
2003 2002 2003 2002
--------- ----------- ----------- -----------
Income available to common stockholders,
as reported $ 843 $ 9,324 $ 7,817 $ 15,570
Add: Stock-based employee compensation
expense included in reported net income,
net of related tax effects 346 114 697 313
Deduct: Total stock-based employee
compensation expense determined
under fair value based method for all
awards, net of related tax effects (662) (270) (1,477) (691)
--------- ----------- ----------- -----------
Pro forma net income $ 527 $ 9,168 $ 7,037 $ 15,192
========= =========== =========== ===========
Earnings per share:
Basic-as reported $ 0.04 $ 0.39 $ 0.33 $ 0.66
========= =========== =========== ===========
Basic-pro forma $ 0.02 $ 0.38 $ 0.30 $ 0.64
========= =========== =========== ===========
Diluted-as reported $ 0.04 $ 0.37 $ 0.32 $ 0.64
========= =========== =========== ===========
Diluted-pro forma $ 0.02 $ 0.37 $ 0.29 $ 0.62
========= =========== =========== ===========
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 six months ended June 30, 2003. For purposes of pro
forma disclosures, the estimated fair value of the options is amortized to
expense over the options' vesting period.
Recent Accounting Pronouncements. The Financial Accounting Standards Board
("FASB") issued Statement of Financial Accounting Standards No. 149 "Amendment
of Statement 133 on Derivative Instruments and Hedging Activities" ("SFAS 149")
on April 30, 2003. SFAS 149 amends and clarifies accounting for derivative
instruments, including certain derivative instruments embedded in other
contracts, and for hedging activities under SFAS No. 133. The statement is
effective for contracts entered into or modified after June 30, 2003 and for
hedging relationships designated after June 30, 2003. The adoption of SFAS
No. 149 will have no effect on either our financial position or results of
operations.
In May 2003, the FASB issued Statement No. 150 "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity."
("SFAS 150"). SFAS 150 establishes standards for how an issuer classifies and
measures certain financial instruments with characteristics of both liabilities
and equity. SFAS 150 is effective for financial instruments entered into or
modified after May 31, 2003, and otherwise is effective at the beginning of the
first interim period beginning after June 15, 2003. The adoption of SFAS 150
will not have an impact on our financial statements.
10
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 June 30, 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 JUNE 30, SIX MONTHS ENDED JUNE 30,
--------------------------------- ----------------------------------
2003 2002 2003 2002
--------------------------------- ----------------------------------
Revenues $ 2,709,189 $ 1,985,347 $ 5,991,097 $ 3,530,670
Cost of sales and operations 2,653,884 1,943,640 5,878,240 3,450,575
Gross margin, excluding depreciation 55,305 41,707 112,857 80,095
Operating income 31,839 23,411 65,448 44,074
Net income 23,398 16,951 47,749 31,232
JUNE 30, DECEMBER 31,
2003 2002
--------------- --------------
Current assets $ 497,120 $ 602,935
Property and equipment, net 1,070,339 952,753
Other assets 142,962 110,887
Total assets 1,710,421 1,666,575
Current liabilities 560,924 637,249
Long-term debt 526,495 509,736
Other long-term liabilities 22,207 7,980
Partners' capital 600,795 511,610
Total liabilities and partners' capital 1,710,421 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 and six months ended June 30, 2002,
are summarized as follows (in thousands):
THREE MONTHS SIX MONTHS
ENDED ENDED
JUNE 30, 2002 JUNE 30, 2002
------------- -------------
Revenues $ 45,140 $ 85,813
Costs and expenses (26,943) (53,315)
------------ ------------
Income from operations 18,197 32,498
Other income (expense) (4,708) (9,382)
------------ ------------
Income before income taxes 13,489 23,116
Income tax expense (5,271) (9,034)
------------ ------------
Income from discontinued operations $ 8,218 $ 14,082
============ ============
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, SFAS 138 and SFAS 149, 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 first six months
of 2003 we recorded a $0.6 million loss for the decrease in the fair value of
our derivatives and recognized a $1.4 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 June 30, 2003 Accumulated OCI consisted of unrealized losses of $0.8
million ($0.4 million, net of tax) on our oil
12
hedging instruments, $0.5 million ($0.3 million, net of tax) related to pension
liabilities and an unrealized gain of $5.3 million ($2.7 million, net of tax)
related to our equity in the OCI gains of PAA. At June 30, 2003, the liability
related to our open oil hedging instruments was included in current liabilities
($1.2 million), other long-term liabilities ($0.2 million), and deferred income
taxes (a tax benefit of $0.4 million).
During the first six months of 2002 oil sales revenues were reduced by $0.3
million for non-cash expense related to the amortization of option premiums. As
of June 30, 2003, $0.8 million ($0.4 million, net of tax) of deferred net losses
on our oil derivative instruments recorded in OCI are expected to be
reclassified to earnings during the following twelve months.
At June 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
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 June 2003 we restructured our secured term loan facility with a group of
banks. The restructured $60.0 million term loan is repayable in twelve quarterly
installments of $5.0 million commencing in August 2003 with a final maturity of
May 31, 2006. 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 June 30, 2003 $60.0 million was outstanding under the secured
term loan facility. Our average borrowing rate for the six months ended June 30,
2003 was 4.4% (4.3% at June 30, 2003).
To secure the term loan, we pledged 100% of the shares of stock of our
subsidiaries and pledged 5.2 million 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 (as defined) and a consolidated debt
service coverage ratio (as defined in the agreement) of 1.0 to 1.0. At June 30,
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 and six months ended June 30, 2003 and 2002 (in thousands, except per
share amounts):
THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30,
------------------------------------------- ------------------------------------------
2003 2002 2003 2002
------------------------------------------- ------------------------------------------
BASIC DILUTED BASIC DILUTED BASIC DILUTED BASIC DILUTED
------------------------------------------- ------------------------------------------
Income from continuing operations $ 1,096 $ 1,096 $ 1,456 $ 1,456 $ 7,487 $ 7,487 $ 2,188 $ 2,188
Preferred dividends (253) (253) (350) (350) (603) (603) (700) (700)
------- ------- -------- -------- -------- -------- -------- --------
Income from continuing operations
available to common stockholders 843 843 1,106 1,106 6,884 6,884 1,488 1,488
Income from discontinued operations,
net of tax - - 8,218 8,218 - - 14,082 14,082
Effect of accounting changes, net of tax - - - - 933 933 -
------- ------- -------- -------- -------- -------- -------- --------
Income available to common stockholders $ 843 $ 843 $ 9,324 $ 9,324 $ 7,817 $ 7,817 $ 15,570 $ 15,570
======= ======= ======== ======== ======== ======== ======== ========
Weighted average number of shares of
common stock outstanding 23,475 23,475 23,883 23,883 23,727 23,727 23,759 23,759
Effect of dilutive securities
Convertible preferred stock - 1,176 - - - - - -
Stock options and restricted stock - 500 - 702 - 445 - 614
------- ------- -------- -------- -------- -------- -------- --------
Weighted average common shares,
including dilutive effect 23,475 25,151 23,883 24,585 23,727 24,172 23,759 24,373
======= ======= ======== ======== ======== ======== ======== ========
Earnings per share
Continuing operations $ 0.04 $ 0.04 $ 0.05 $ 0.04 $ 0.29 $ 0.28 $ 0.06 0.06
Discontinued operations - - 0.34 0.33 - - 0.60 0.58
Effect of accounting changes - - - - 0.04 0.04 -
------- ------- -------- -------- -------- -------- -------- --------
Income available to common
stockholders $ 0.04 $ 0.04 $ 0.39 $ 0.37 $ 0.33 $ 0.32 $ 0.66 $ 0.64
======= ======= ======== ======== ======== ======== ======== ========
In the six months ended June 30, 2003 and the three months and six months
ended June 30, 2002 our cumulative convertible preferred stock was not included
in the computation of diluted earnings per share because the effect was
antidilutive.
NOTE 7 -- STOCKHOLDERS' EQUITY
In June 2003 we paid $23.3 million to retire the 46,600 outstanding shares
of our Series D Cumulative Convertible Preferred Stock, or Series D Preferred.
The Series D Preferred was convertible into 1,671,416 shares of common stock at
a price of $13.94 per share and paid an annual dividend of $30.00 per share.
Our Board of Directors has authorized the repurchase of up to eight million
shares of our common stock. Through December 31, 2002, we had repurchased a
total of 4.1 million shares at a total cost of approximately $91.3 million. In
the first six months of 2003 we have repurchased an additional 0.8 million
shares at a total cost of $9.0 million.
NOTE 8 -- RELATED PARTY TRANSACTIONS
GOVERNANCE OF PAA
14
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 value assurance agreements with Sable Investments, Kafu
Holdings, E-Holdings and other parties with respect to the 5.2 million
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 six months ended June 30, 2003 and 2002, sales of oil
to PAA under the agreement totalled approximately $13.7 million and $10.4
million, respectively, including the royalty share of production. For the six
months ended June 30, 2003 and 2002, PAA charged us $0.1 million in each period
in marketing fees.
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.
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 six months ended June 30, 2003 PXP billed
us $272,000 for services provided to us under these agreements and we billed PXP
$86,000 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 six months ended June 30, 2003 and 2002 we paid Gulf Coast $10,000
and $214,000, respectively, for aircraft
15
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 9 -- 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.
NOTE 10 -- SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Selected cash payments and noncash activities were as follows (in
thousands):
THREE MONTHS SIX MONTHS
ENDED JUNE 30, ENDED JUNE 30,
--------------------- -----------------------
2003 2002 2003 2002
-------- -------- -------- ---------
Cash paid for interest $ 440 $ 456 $ 884 $ 14,893
-------- -------- -------- ---------
Cash paid for taxes $ 867 $ 528 $ 1,532 $ 3,272
======== ======== ======== =========
Noncash sources of investing and financing activities:
Tax benefit from exercise of employee stock options $ 3 $ 1,191 $ 118 $ 1,736
======== ======== ======== =========
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., or PAA. PAA is a publicly traded master limited partnership actively
engaged in the midstream energy markets. As of June 30, 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 50% of our total assets
as of June 30, 2003 and the book value of our Florida oil properties represents
33%. 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 $31.48 on June 30, 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 six months of 2003 we had oil revenues of $11.3 million
and distributions received from PAA attributable to our general and limited
partner interests totaled $15.3 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 June 30, 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.
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.
Our oil production expenses include salaries and benefits of personnel
involved in production activities, electric costs, maintenance costs, 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 June 30, 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 JUNE 30, SIX MONTHS ENDED JUNE 30,
---------------------------- -------------------------
2003 2002 2003 2002
----------- ----------- ---------- ----------
Production (MBbls)
206 230 438 477
Sales (MBbls)
203 202 479 418
Average NYMEX price per bbl $ 28.91 $ 26.27 $ 31.32 $ 24.02
Hedging and derivative cash
settlements (1.88) (0.63) (2.97) (0.60)
Differential (7.50) (2.58) (7.05) (2.57)
------- ------- ------- -------
Average realized price per bbl 19.53 23.06 21.30 20.85
Production expenses per bbl (7.49) (6.46) (7.05) (6.45)
Production and ad valorem taxes per bbl (1.15) (0.62) (1.33) (0.55)
Oil transportation expenses per bbl (4.48) (4.41) (4.23) (4.38)
------- ------- ------- -------
Gross margin per bbl $ 6.41 $ 11.57 $ 8.69 $ 9.47
======= ======= ======= =======
DD&A per bbl (oil & gas properties) $ 4.68 $ 4.02 $ 4.68 $ 3.87
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 JUNE 30, 2003 TO THREE MONTHS ENDED
JUNE 30, 2002
We reported net income of $1.1 million for the second quarter of 2003
compared to income from continuing operations of $1.5 million for the second
quarter of 2002. Including income from discontinued operations we reported net
income of $9.7 million in the second quarter of 2002.
Oil revenues. Our oil revenues, excluding the effect of hedging, decreased
10%, or $0.5 million, from $4.8 million for the second quarter of 2002 to $4.3
million for the second quarter of 2003. The decrease was due to lower realized
prices.
We reported sales volumes from our Florida properties of 203 MBbls in 2003
compared to 202 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 10% on an "as produced" basis,
with production volumes of 206 MBbls in 2003 compared to 230 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. 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 decreased 15%, or $3.53, to $19.53 per
Bbl for the second quarter of 2003 from $23.06 per Bbl for the second quarter of
2002. The decrease primarily reflects an increase in the differential to the
NYMEX oil price which averaged $7.50 per Bbl in the second quarter of 2003
compared to $2.58 per Bbl in the second quarter of 2002. The NYMEX oil price
averaged $28.91 per Bbl in 2003 versus $26.27 per Bbl in 2002. Hedging and
derivatives had the effect of decreasing our average price per Bbl by $1.88 in
2003 and $0.63 in 2002.
Production expenses. Our production expenses increased 15%, or $0.2 million,
to $1.5 million ($7.49 per Bbl) for the
19
second quarter of 2003 from $1.3 million ($6.46 per Bbl) for the second quarter
of 2002. The increase is primarily attributable to increased fuel and
electricity costs.
Production and ad valorem taxes. Our production and ad valorem taxes
increased 100%, or $0.1 million, to $0.2 million for the second quarter of 2003
from $0.1 million for the second quarter of 2002 primarily due to the expiration
of severance tax exemptions for several wells in the second quarter of 2002.
Unit production and ad valorem taxes for 2003 were $1.15 per Bbl compared to
$0.62 per Bbl in 2002.
Depreciation, depletion and amortization. Our depreciation, depletion and
amortization, or DD&A expense decreased 17%, or $0.2 million, to $1.0 million
for the second quarter of 2003 from $1.2 million for the second quarter of 2002.
The decrease is due to a decrease in the per unit DD&A rate ($4.68 per Bbl in
2003 versus $4.02 per Bbl in 2002).
Accretion of asset retirement obligation. Accretion expense for the second
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.
Other operating expenses. Other operating expenses include a $0.1 million
loss on the disposition of materials and supplies inventory.
Equity in earnings of Plains All American Pipeline, L.P. Our equity in
earnings of PAA increased $0.1 million to $5.4 million for the second quarter of
2003 from $5.3 million for the second quarter of 2002. PAA reported net income
of $23.4 million in the second quarter of 2003 compared to $17.0 million in the
second quarter of 2002. Our ownership interest in PAA was 24% at June 30, 2003
and 29% at June 30, 2002.
Gain (loss) on derivatives. As previously discussed, we were required to
discontinue hedge accounting effective February 1, 2003. As a result, in the
second quarter of 2003 we recorded a $1.3 million loss reflecting the decrease
in the fair value of our derivatives and recognized a $0.4 million loss on cash
settlements of such derivatives.
Interest expense. Our interest expense decreased $1.3 million, to $0.5
million for the second quarter of 2003 from $1.8 million for the second quarter
of 2002, primarily reflecting lower outstanding debt.
Income tax expense. Our income tax expense decreased $0.5 million to $1.0
million for the second quarter of 2003 from $1.5 million for the second quarter
of 2003. The decrease was due to lower pre-tax income from continuing operations
and a lower effective tax rate. Our effective tax rate was 47.9% in the second
quarter of 2003 compared to 50.4% in the second 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.
Income from discontinued operations. Income from discontinued operations of
$8.2 million in the second quarter of 2002 reflects the net after tax earnings
of PXP, which was spun off in the fourth quarter of 2002.
COMPARISON OF SIX MONTHS ENDED JUNE 30, 2003 TO SIX MONTHS ENDED JUNE 30, 2002
We reported net income of $8.4 million for the first six months of 2003
compared to income from continuing operations of $2.2 million for the first six
months of 2002. Including income from discontinued operations we reported net
income of $16.3 million in the first six months of 2002.
Oil revenues. Our oil revenues, excluding the effect of hedging, increased
29%, or $2.6 million, from $9.0 million for the first half of 2002 to $11.6
million for the first half of 2003. The increase was primarily due to higher
sales volumes that increased revenues by $1.5 million and higher realized prices
that increased revenues by $1.1 million.
We reported sales volumes from our Florida properties of 479 MBbls in 2003
compared to 418 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 8% on an "as produced" basis, with
production volumes of 438 MBbls in 2003 compared to 477 MBbls in 2002.
20
Our average realized price for oil increased 2%, or $0.45, to $21.30 per Bbl
for the first half of 2003 from $20.85 per Bbl for the first half of 2002. The
increase primarily reflects an improvement in the NYMEX oil price, which
averaged $31.32 per Bbl in 2003 versus $24.02 per Bbl in 2002, offset by an
increase in the average differential for location and quality from $2.57 per Bbl
in 2002 to $7.05 per Bbl in 2003. Hedging and derivatives had the effect of
decreasing our average price per Bbl by $2.97 in 2003 and $0.60 in 2002.
Production expenses. Our production expenses increased 26%, or $0.7 million,
to $3.4 million ($7.05 per Bbl) for the first half of 2003 from $2.7 million
($6.45 per Bbl) for the first half of 2002. The per Bbl increase is primarily
attributable to increased fuel and electricity costs.
Production and ad valorem taxes. Our production and ad valorem taxes
increased 200%, or $0.4 million, to $0.6 million for the first half of 2003 from
$0.2 million for the first half 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 $1.33 per
Bbl compared to $0.55 per Bbl in 2002.
Oil transportation expenses. Oil transportation expenses increased 11%, or
$0.2 million, from $1.8 million in the first half of 2002 to $2.0 million in
the first half of 2003. On a per Bbl basis, oil transportation expenses
decreased from $4.38 per Bbl in 2002 to $4.23 per Bbl in 2003.
Accretion of asset retirement obligation. Accretion expense for the first
half 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.
Other operating expenses. Other operating expenses include $0.1 million loss
on the disposition of materials and supplies inventory.
Equity in earnings of Plains All American Pipeline, L.P. Our equity in
earnings of PAA increased $2.1 million to $11.7 million for the first half of
2003 from $9.6 million for the first half of 2002. PAA reported net income of
$47.7 million in the first half of 2003 compared to $31.2 million in the first
half of 2002. Our ownership interest in PAA was 24% at June 30, 2003 and 29% at
June 30, 2002.
Gain on Plains All American Pipeline, L.P. unit offerings. In the first half
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
first half of 2003 we recorded a $0.6 million loss for the decrease in the fair
value of our derivatives and recognized a $1.1 million loss on cash settlements
of such derivatives.
Interest expense. Our interest expense decreased $2.5 million, to $1.0
million for the first half of 2003 from $3.5 million for the first half of 2002,
primarily reflecting lower outstanding debt.
Income tax expense. Our income tax expense increased $4.7 million to $6.9
million for the first half of 2003 from $2.2 million for the first half 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 half of 2003
compared to 50.4% in the first half 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 half 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.
Income from discontinued operations. Income from discontinued operations of
$14.1 million in the first half of 2002 reflects the net after tax earnings of
PXP, which was spun off in the fourth quarter of 2002.
21
LIQUIDITY AND CAPITAL RESOURCES
GENERAL
At June 30, 2003 we had negative working capital of $21.2 million, primarily
reflecting $20.0 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 (see
"-- Related Party Transactions - Value Assurance Agreements"), 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 June 30, 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 declared distribution of $0.55 per unit (an annual
distribution rate of $2.20 per unit), which will be paid on August 14 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).
22
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
------------------------------ ------------------------------ ------------------------------
DISTRIBUTION EXCESS DISTRIBUTION EXCESS DISTRIBUTION EXCESS
OVER MQD OVER MQD 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 $ 0.5500 $ 0.1000 $ 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. In June 2003 the facility was restructured to allow us to borrow an
additional $24 million that was used to repurchase the 46,600 outstanding shares
of our Series D Cumulative Convertible Preferred Stock and pay accrued dividends
and related expenses. At June 30, 2003, $60.0 million was outstanding under the
secured term loan facility. The term loan is repayable in twelve quarterly
installments of $5.0 million each, commencing on August 31, 2003 with a final
maturity of May 31, 2006. 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 six months of 2003 was
4.4% (4.3% at June 30, 2003).
To secure the term loan, we pledged 100% of the shares of stock of our
subsidiaries and pledged 5.2 million 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 (as defined) and a consolidated debt
service coverage ratio (as defined in the agreement) of 1.0 to 1.0.
CASH FLOWS FROM CONTINUING OPERATIONS
SIX MONTHS ENDED JUNE 30,
-----------------------------------
2003 2002
-----------------------------------
(IN MILLIONS)
Cash provided by (used in):
Operating activities $ 12.3 $ 17.2
Investing activities (2.1) (4.8)
Financing activities (17.2) 10.1
Operating Activities. Net cash provided by operating activities in the first
half of 2003 totaled $12.3 million compared to
23
$17.2 million in the first half of 2003. The decrease was primarily due to lower
realized oil prices and higher production expenses.
Investing Activities. In the first half of 2003 net cash used in investing
activities totaled $2.1 million compared to $4.8 million in the first half of
2002. Oil and gas capital expenditures were $1.5 million in the first half of
2003 compared to $4.7 million in the first half of 2002. In the first half 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.
Financing activities. Cash used in financing activities in the first half of
2003 included a net increase in long-term debt of $15.0 million, $1.4 million in
proceeds from issuances of our common stock, expenditures of $9.0 million for
the repurchase of $0.8 million shares of our common stock, $23.3 million to
redeem our outstanding Series D preferred stock, $0.6 million for the payment of
costs incurred in connection with our term loan and $0.6 million for the payment
of preferred stock dividends. Cash used in financing activities in the first
half of 2002 included a net increase in long-term debt of $6.0 million, $4.4
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 six months of 2003 we made aggregate capital
expenditures of $1.5 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 June 30, 2003 we have repurchased an additional 0.8 million
shares at a total cost of $9.0 million. We intend to make additional repurchases
in 2003 and expect to fund the repurchases from cash flows.
CONTRACTUAL OBLIGATIONS
At June 30, 2003, the aggregate amounts of contractually obligated payment
commitments for the next five years are as follows (in thousands):
2003 2004 2005 2006 2007 THEREAFTER
---------- ---------- ----------- ---------- --------- ----------
Long-term debt $ 10,000 $ 20,000 $ 20,000 $ 10,000 $ - $ -
Operating leases 12 23 23 6 - -
---------- ---------- ----------- ---------- --------- ---------
$ 10,012 $ 20,023 $ 20,023 $ 10,006 $ - $ -
========== ========== =========== ========== ======== ========
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 second quarter of 2003 PAA paid a
quarterly distribution of $0.55 per unit ($2.20 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
24
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 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 June 30, 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.
25
VALUE ASSURANCE AGREEMENTS
We entered into value assurance agreements with Sable Investments,
Kafu Holdings, E-Holdings and other parties with respect to the 5.2 million
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.
OUR RELATIONSHIP WITH PAA
We have ongoing relationships with PAA, including:
o 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 six months of 2003, sales to PAA under the agreement totalled
$13.7 million, including the royalty share of production, and PAA
charged us $0.1 million in marketing fees; and
o 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 six months ended June 30, 2003 PXP billed
us $272,000 for services provided to us under these agreements and we billed PXP
$86,000 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 that we have in place, certain factors may
impact our future financial results. The most significant of these factors
relate to our commodity pricing and risk management activities, write-downs
under full cost ceiling test rules and oil and gas reserves. These policies and
their effect on certain of our accounting policies are discussed in our Annual
Report on Form 10-K for the year ended December 31, 2002.
Write-downs under full cost ceiling test rules. Based on the book value of
our proved oil and gas properties (including related deferred income taxes) and
our estimated proved reserves as of June 30, 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 $16.00 per barrel. Based on an estimated oil
differential for 2003 plus oil transportation of $11.00 to $12.75 per barrel,
we would have a write-down at a NYMEX crude oil index price of $27.00 to $28.75
per barrel.
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 June 30, 2003, and other applicable SEC filings by PAA.
26
RECENT ACCOUNTING PRONOUNCEMENTS
The Financial Accounting Standards Board (FASB) issued Statement of
Financial Accounting Standards No. 149 "Amendment of Statement 133 on Derivative
Instruments and Hedging Activities" (SFAS 149) on April 30, 2003. SFAS 149
amends and clarifies accounting for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities
under SFAS No. 133. The statement is effective for contracts entered into or
modified after June 30, 2003 and for hedging relationships designated after June
30, 2003. The adoption of SFAS No.149 will have no effect on either our
financial position or results of operations.
In May 2003, the FASB issued Statement No. 150 "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity."
(SFAS 150). SFAS 150 establishes standards for how an issuer classified and
measures certain financial instruments with characteristics of both liabilities
and equity. SFAS 150 is effective for financial instruments entered into or
modified after May 31, 2003, and otherwise is effective at the beginning of the
first interim period beginning after June 15, 2003. The adoption of SFAS 150
will not have an impact on our financial statements.
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:
o the consequences of any potential change in the relationship between us
and PXP;
o 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;
o 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);
o 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;
o uncertainties inherent in the development and production of oil and gas
and in estimating reserves;
o unexpected future capital expenditures (including the amount and nature
thereof);
o impact of oil and gas price fluctuations;
o the effects of competition;
o the success of our risk management activities;
o the availability (or lack thereof) of acquisition or combination
opportunities;
o the impact of current and future laws and governmental regulations;
o environmental liabilities that are not covered by an effective indemnity
or insurance, and
o general economic, market, industry or business conditions.
27
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 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, SFAS 138 and SFAS 149, 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 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 first six months
of 2003 we recorded a $0.6 million loss for the decrease in the fair value of
our derivatives and recognized a $1.4 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 June 30, 2003 Accumulated OCI consisted of unrealized losses of $0.8
million ($0.4 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 $5.3 million ($2.7 million, net of tax) related to our equity in the OCI
gains of PAA. At June 30, 2003, the liability related to our open oil hedging
instruments was included in current liabilities ($1.2 million), other long-term
liabilities ($0.2 million), and deferred income taxes (a tax benefit of $0.4
million).
During the first six months of 2002 oil sales revenues were reduced by $0.3
million for non-cash expense related to the amortization of option premiums. As
of June 30, 2003, $0.8 million ($0.4 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 July 31, 2003, we had the following open oil
derivative positions:
BARRELS PER DAY
---------------------------------------------------
2003 2004 2005 2006
------------------------- -------------------------
Swaps
Average price $26.10/bbl 1,500 - - -
Average price $24.07/bbl - 1,000 - -
Average price $24.30/bbl - - 500 -
Average price $23.85/bbl - - - 500
29
Assuming our second quarter 2003 production volumes are held constant in
subsequent periods, these positions represent approximately 66%, 44%, 22%, and
22% of oil production in 2003, 2004, 2005 and 2006, 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 oil sales revenues of $0.3 million and $0.3 million in the first
six months of 2003 and 2002, respectively.
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 June 30, 2003 we had $60.0 million
outstanding under our term loan, repayable $10.0 million in 2003, $20.0 million
in 2004, $20.0 million in 2005 and $10.0 million in 2006. 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
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 as of
June 30, 2003 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 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The following items were presented for approval to stockholders of record on
March 21, 2003 at the Company's 2003 annual meeting of stockholders which was
held on May 15, 2003 in Houston, Texas:
(i) Election of Directors:
Abstained or
For Against Withheld
--- ------- ------------
James C. Flores 19,054,666 - 917,171
William H. Hitchcock 15,432,087 - 4,539,750
William C. O'Malley 19,054,626 - 917,211
D. Martin Phillips 19,054,551 - 917,286
Robert V. Sinnott 19,054,626 - 917,211
J. Taft Symonds 19,054,591 - 917,246
(ii)Ratification of
PricewaterhouseCoopers LLP,
independent certified public
accountants, as auditors of the
Company's financial statements
for the fiscal year ended
December 31, 2003. 18,921,195 1,047,726 2,917
Of the 24,197,902 shares of common stock issued and outstanding on March 22,
2002, 19,971,837 were voted.
All matters received the required number of votes for approval.
32
ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
10.1 First Amendment to Secured Term Loan Agreement dated as of May
9, 2003, by and among Plains Resources Inc., Bank of Montreal
as Administrative Agent, Bank One, NA, as Syndication Agent,
Wells Fargo Bank Texas, NA, as Collateral Agent and
Documentation Agent, and the Lenders named therein.
10.2 Second Amendment to Secured Term Loan Agreement dated as of
June 6, 2003, by and among Plains Resources Inc., Bank of
Montreal as Administrative Agent, Bank One, NA, as Syndication
Agent, Wells Fargo Bank Texas, NA, as Collateral Agent and
Documentation Agent, and the Lenders named therein.
31.1 Certification of Chief Executive Officer, as Adopted Pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 Certification of Chief Financial Officer, as Adopted Pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1 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
32.2 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
(i) estimates of certain results for the three months ended June 30, 2003 and
the year ended December 31, 2003; and (ii) the Company's press release reporting
first quarter 2003 earnings.
ITEMS 2, 3 & 5 ARE NOT APPLICABLE AND HAVE BEEN OMITTED.
33
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned and thereunto duly authorized.
PLAINS RESOURCES INC.
Date: August 14, 2003 By: /s/ Stephen A. Thorington
---------------------------------
Stephen A. Thorington
Executive Vice President and
Chief Financial Officer (Principal
Financial and Accounting Officer)
34
INDEX TO EXHIBITS
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
10.1 First Amendment to Secured Term Loan Agreement dated as of May
9, 2003, by and among Plains Resources Inc., Bank of Montreal
as Administrative Agent, Bank One, NA, as Syndication Agent,
Wells Fargo Bank Texas, NA, as Collateral Agent and
Documentation Agent, and the Lenders named therein.
10.2 Second Amendment to Secured Term Loan Agreement dated as of
June 6, 2003, by and among Plains Resources Inc., Bank of
Montreal as Administrative Agent, Bank One, NA, as Syndication
Agent, Wells Fargo Bank Texas, NA, as Collateral Agent and
Documentation Agent, and the Lenders named therein.
31.1 Certification of Chief Executive Officer, as Adopted Pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 Certification of Chief Financial Officer, as Adopted Pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1 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
32.2 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.