Back to GetFilings.com
================================================================================
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, 2002
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 (I.R.S. Employer
jurisdiction of Identification No.)
incorporation or
organization)
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__ (check mark)__ No ____
23,933,000 shares of common stock, $0.10 par value, issued and outstanding
at July 31, 2002.
================================================================================
PLAINS RESOURCES INC. AND SUBSIDIARIES
TABLE OF CONTENTS
Page
----
PART I. FINANCIAL INFORMATION.......................................... 3
CONSOLIDATED FINANCIAL STATEMENTS:
Condensed Consolidated Balance Sheets:
June 30, 2002 and December 31, 2001................................... 3
Consolidated Income Statements:
For the three and six months ended June 30, 2002 and 2001............. 4
Condensed Consolidated Statements of Cash Flows:
For the six months ended June 30, 2002 and 2001....................... 5
Condensed Consolidated Statements of Changes in Stockholders' Equity
For the six months ended June 30, 2002................................ 6
Notes to Consolidated Financial Statements............................. 7
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS........................................................
21
PART II. OTHER INFORMATION.............................................
35
2
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands of dollars)
June 30, December 31,
2002 2001
----------- ------------
(unaudited)
ASSETS
Current Assets
Cash and cash equivalents................................... $ 1,076 $ 1,179
Accounts receivable......................................... 25,326 20,039
Commodity hedging contracts................................. 632 23,257
Inventory................................................... 7,366 6,721
Other current assets........................................ 3,317 1,527
--------- ---------
37,717 52,723
--------- ---------
Property and Equipment
Oil and natural gas properties--full cost method............ 986,649 941,404
Other property and equipment................................ 4,051 4,003
--------- ---------
990,700 945,407
Less allowance for depreciation, depletion and amortization. (453,427) (437,982)
--------- ---------
537,273 507,425
--------- ---------
Investment in Plains All American Pipeline, L.P................ 63,167 64,626
--------- ---------
Other Assets................................................... 18,419 24,014
--------- ---------
$ 656,576 $ 648,788
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable and other current liabilities.............. $ 46,042 $ 53,895
Commodity hedging contracts................................. 12,659 --
Interest payable............................................ 8,442 8,286
Notes payable............................................... 511 511
--------- ---------
67,654 62,692
--------- ---------
Long-Term Debt
Bank debt................................................... 17,500 11,500
Subordinated debt........................................... 269,325 269,539
Other....................................................... 1,022 1,022
--------- ---------
287,847 282,061
--------- ---------
Other Long-Term Liabilities.................................... 7,845 4,889
--------- ---------
Deferred Income Taxes.......................................... 39,966 44,294
--------- ---------
Stockholders' Equity........................................... 253,264 254,852
--------- ---------
$ 656,576 $ 648,788
========= =========
See notes to consolidated financial statements.
3
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
(in thousands, except per share data)
Three Months Ended Six Months Ended
June 30, June 30,
----------------- ------------------
2002 2001 2002 2001
------- -------- -------- --------
Revenues
Crude oil and liquids............................... $46,306 $ 45,655 $ 88,108 $ 92,715
Natural gas......................................... 2,589 12,346 4,577 23,518
Other operating revenues............................ 13 423 13 423
------- -------- -------- --------
48,908 58,424 92,698 116,656
------- -------- -------- --------
Costs and Expenses
Production expenses................................. 19,282 17,850 38,007 34,030
General and administrative.......................... 3,982 11,479 8,101 15,560
Depreciation, depletion and amortization............ 7,984 6,585 15,834 13,384
------- -------- -------- --------
31,248 35,914 61,942 62,974
------- -------- -------- --------
Income from Operations................................. 17,660 22,510 30,756 53,682
Other Income (Expense)
Equity in earnings of Plains All American Pipeline,
L.P............................................... 5,256 3,755 9,606 10,591
Gain on Plains All American Pipeline, L.P. units.... -- 148,213 -- 150,171
Interest expense.................................... (6,516) (6,827) (12,895) (13,823)
Interest and other income (expense)................. 26 (669) 63 (2)
------- -------- -------- --------
Income Before Income Taxes and Cumulative Effect
of Accounting Change................................. 16,426 166,982 27,530 200,619
Income tax benefit (expense)........................
Current......................................... (585) (8,449) 1,937 (8,927)
Deferred........................................ (6,167) (58,431) (13,197) (70,638)
------- -------- -------- --------
Income Before Cumulative Effect of Accounting
Change............................................... 9,674 100,102 16,270 121,054
Cumulative effect of accounting change, net of tax
benefit........................................... -- -- -- (1,986)
------- -------- -------- --------
Net Income............................................. 9,674 100,102 16,270 119,068
Preferred dividend requirement...................... (350) (24,947) (700) (26,546)
------- -------- -------- --------
Income Attributable to Common Shares................... $ 9,324 $ 75,155 $ 15,570 $ 92,522
======= ======== ======== ========
Earnings per Share
Income Before Cumulative Effect of Accounting Change
Basic............................................... $ 0.39 $ 3.83 $ 0.66 $ 5.10
Diluted............................................. $ 0.38 $ 2.68 $ 0.64 $ 3.38
Net Income.............................................
Basic............................................... $ 0.39 $ 3.83 $ 0.66 $ 4.99
Diluted............................................. $ 0.38 $ 2.68 $ 0.64 $ 3.31
Weighted Average Shares Outstanding
Basic............................................... 23,883 19,631 23,759 18,547
Diluted............................................. 25,517 28,494 25,305 28,757
See notes to consolidated financial statements.
4
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands of dollars)
(unaudited)
Six Months Ended
June 30,
-------------------
2002 2001
-------- ---------
Cash Flows from Operating Activities
Net income.............................................................. $ 16,270 $ 119,068
Items not affecting cash flows from operating activities:
Depreciation, depletion and amortization.............................. 15,834 13,384
Equity in earnings of Plains All American Pipeline, L.P............... (9,606) (10,591)
Distributions from Plains All American Pipeline, L.P.................. 14,140 17,907
Gain on sale of Plains All American Pipeline, L.P. units.............. -- (150,171)
Deferred income taxes................................................. 13,197 71,384
Cumulative effect of accounting change................................ -- 1,986
Change in derivative fair value....................................... -- 1,227
Noncash compensation.................................................. 623 4,246
Other................................................................. 422 679
Change in assets and liabilities from operating activities:
Current and other assets.............................................. (6,968) 11,267
Current and other liabilities......................................... (6,967) (12,682)
-------- ---------
Net cash provided by operating activities............................... 36,945 67,704
-------- ---------
Cash Flows from Investing Activities
Oil and gas properties.................................................. (47,061) (62,067)
Other property and equipment............................................ (48) (405)
Sale of Plains All American Pipeline, L.P. units........................ -- 105,899
Investment in Plains All American Pipeline, L.P......................... -- (2,763)
-------- ---------
Net cash used in investing activities................................... (47,109) 40,664
-------- ---------
Cash Flows from Financing Activities
Net change in long-term debt............................................ 6,000 (27,300)
Exercise of stock options............................................... 4,411 2,892
Treasury stock purchases................................................ -- (39,528)
Preferred stock dividends paid.......................................... (350) (7,648)
Other................................................................... -- (68)
-------- ---------
Net cash provided by financing activities............................... 10,061 (71,652)
-------- ---------
Net increase (decrease) in cash and cash equivalents..................... (103) 36,716
Decrease in cash due to deconsolidation of Plains All American Pipeline,
L.P................................................................... -- (3,425)
Cash and cash equivalents, beginning of period........................... 1,179 5,080
-------- ---------
Cash and cash equivalents, end of period................................. $ 1,076 $ 38,371
======== =========
See notes to consolidated financial statements.
5
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
(in thousands)
(unaudited)
Six Months Ended
June 30, 2002
----------------
Shares Amount
------ --------
Series D Cumulative Convertible Preferred Stock
Balance, beginning and end of period........................... 47 $ 23,300
====== --------
Common Stock
Balance, beginning of period................................... 27,677 2,768
Common stock issued upon exercise of stock options and other... 100 10
------ --------
Balance, end of period......................................... 27,777 2,778
====== --------
Additional Paid-in Capital
Balance, beginning of period................................... 268,520
Common stock issued upon exercise of stock options and other... 3,148
--------
Balance, end of period......................................... 271,668
--------
Retained Earnings
Balance, beginning of period................................... 37,676
Net income..................................................... 16,270
Preferred stock dividends...................................... (700)
Treasury stock issued for less than cost....................... (926)
--------
Balance, end of period......................................... 52,320
--------
Accumulated Other Comprehensive Income
Balance, beginning of period................................... 13,930
Other comprehensive income..................................... (23,717)
--------
Balance, end of period......................................... (9,787)
--------
Treasury Stock
Balance, beginning of period................................... (4,121) (91,342)
Treasury stock issued upon exercise of stock options and other. 267 4,327
------ --------
Balance, end of period......................................... (3,854) (87,015)
====== --------
Total............................................................. $253,264
========
See notes to consolidated financial statements.
6
PLAINS RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Note 1--Organization and Accounting Policies
These consolidated financial statements include the accounts of Plains
Resources Inc. ("Plains", "our", or "we") and our wholly owned subsidiaries. We
account for our interest in Plains All American Pipeline, L.P. ("PAA") on the
equity method of accounting.
These consolidated financial statements and related notes present our
consolidated financial position as of June 30, 2002 and December 31, 2001, the
results of our operations and our cash flows for the three and six months ended
June 30, 2002 and 2001 and the changes in our stockholders' equity for the six
months ended June 30, 2002. The results for the six months ended June 30, 2002,
are not necessarily indicative of the final results to be expected for the full
year. These financial statements have been prepared in accordance with the
instructions with respect to interim reporting as prescribed by the Securities
and Exchange Commission ("SEC"). For further information, refer to our Form
10-K for the year ended December 31, 2001, filed with the SEC.
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.
We are an independent energy company that is engaged in the "Upstream" oil
and gas business. The Upstream business acquires, exploits, develops, explores
for and produces crude oil and natural gas. Our Upstream activities are all
located in the United States. We participate in the "Midstream" oil and gas
business, which consists of the marketing, transportation and terminalling of
crude oil, through our investment in PAA. All of PAA's Midstream activities are
conducted in the United States and Canada.
We evaluate the capitalized costs of our oil and natural gas properties on
an ongoing basis and have utilized the most recently available information to
estimate our reserves at June 30, 2002, in order to determine the realizability
of such capitalized costs. Future events, including drilling activities,
product prices and operating costs, may affect future estimates of such
reserves.
Inventories. Crude oil inventories are carried at the lower of the cost to
produce or market value. Materials and supplies inventories are stated at the
lower of cost or market, with cost determined on the average cost method. Crude
oil inventories totaled $1.8 million at June 30, 2002 and $1.5 million at
December 31, 2001. Materials and supplies inventories totaled $5.6 million at
June 30, 2002 and $5.2 million at December 31, 2001.
Recent Accounting Pronouncements. In April 2002, Statement of Accounting
Standards ("SFAS") No. 145, "Rescission of FASB Statements No. 4, 44 and 64,
Amendment of FASB Statement No. 13, and Technical Corrections," was issued.
SFAS 145 rescinds SFAS 4 and SFAS 64 related to classification of gains and
losses on debt extinguishment such that most debt extinguishment gains and
losses will no longer be classified as extraordinary. SFAS 145 also amends SFAS
13 with respect to sales-leaseback transactions. The provisions of SFAS 145
with respect to sales-leaseback transactions have no effect on our financial
statements As a result of the provisions of SFAS 145 with respect to debt
extinguishments, the $10.3 million of debt extinguishment costs related to our
refinancing of certain debt instruments in the third quarter of 2002 will not
be classified as an extraordinary item in our statement of income.
7
PLAINS RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
In July 2002, SFAS No. 146, "Accounting For Costs Associated with Exit or
Disposal Activities" was issued. SFAS 146 is effective for exit or disposal
activities initiated after December 31, 2002 and does not require previously
issued financial statements to be restated. We will account for exit or
disposal activities initiated after December 31, 2002 in accordance with the
provisions of SFAS 146.
Note 2--Investment in PAA
As of June 30, 2002, our aggregate ownership in PAA was approximately 29%.
Our investment accounted for using the equity method of accounting, under which
we record only our proportionate share of PAA' s results of operations and
other comprehensive income.
The following table presents unaudited summarized financial statement
information of PAA (in thousands of dollars):
Three Months Ended Six Months Ended
June 30, June 30,
--------------------- ---------------------------
2002 2001 2002 2001
---------- ---------- ------------- -------------
Revenues............................... $1,985,347 $1,586,617 $3,530,670 $3,106,741
Cost of sales and operations........... 1,943,640 1,550,230 3,450,575 3,037,624
Gross margin........................... 41,707 36,387 80,095 69,117
Net income............................. 16,951 7,067 31,232 20,082
At At
Jun. 30, 2002 Dec. 31, 2001
------------- -------------
Current assets......................... $ 587,115 $ 558,082
Property and equipment, net............ 625,316 604,919
Pipeline linefill...................... 58,242 57,367
Other assets........................... 67,331 40,883
Total assets........................... 1,338,004 1,261,251
Current liabilities.................... 553,692 505,160
Long-term debt......................... 381,591 351,677
Other long-term liabilities............ 4,785 1,617
Partners' capital...................... 397,936 402,797
Total liabilities and partners' capital 1,338,004 1,261,251
Note 3--Derivative Instruments and Hedging Activities
Derivative instruments are accounted for in accordance with SFAS No. 133
"Accounting for Derivative Instruments and Hedging Activities" as amended by
SFAS 137 and SFAS 138 ("SFAS 133"). Under 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 unrealized gain or loss on the derivative is deferred in
accumulated Other Comprehensive Income ("OCI"), a component of Stockholders'
Equity. At June 30, 2002 all open positions qualified for hedge accounting.
Gains and losses on crude oil hedging instruments related to OCI and
adjustments to carrying amounts on hedged volumes are included in oil and gas
revenues in the period that the related volumes are delivered. Gains and losses
on crude oil hedging instruments representing hedge ineffectiveness, which is
measured on a quarterly basis, are included in oil and gas revenues in the
period in which they occur.
8
PLAINS RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
During the first six months of 2002 gains of $6.8 million were relieved from
OCI and the fair value of open positions decreased $18.9 million. At June 30,
2002, the unrealized loss on our derivative contracts included in OCI was $9.1
million. The related assets and liabilities were included in current assets and
liabilities ($0.6 and $12.7 million, respectively), other assets and
liabilities ($0.6 million and $3.0 million, respectively), and deferred income
taxes (tax benefit of $6.3 million). Additionally, OCI includes our $0.3
million net of tax equity in the unrealized OCI losses of PAA. As of June 30,
2002, $7.6 million of deferred net losses on derivative instruments recorded in
OCI are expected to be reclassified to earnings during the next twelve-month
period.
Oil and gas revenues for the six months ended June 30, 2002 include $0.1
million of cash losses on hedging instruments, and a $0.6 million non-cash loss
related to the amortization of time value in existence when Derivative
Information Group Issue G20 was implemented in the fourth quarter of 2001.
Assets related to the time value component of the fair value of options are
included in current assets ($0.8 million).
We utilize various derivative instruments to hedge our exposure to price
fluctuations on crude oil sales. The derivative instruments consist primarily
of cash-settled crude oil option and swap contracts entered into with financial
institutions. We do not currently have any natural gas hedges. We also utilize
interest rate swaps and collars to manage the interest rate exposure on our
long-term debt. We currently have an interest rate swap agreement that expires
in October 2004, fixing the interest rate on $7.5 million of borrowing under
our revolving credit facility at 3.9% plus the LIBOR margin set forth in our
credit facility, a total of 5.3% at June 30, 2002.
At June 30, 2002 we had the following open crude oil hedge positions
(barrels per day):
Barrels Per Day
----------------------------
2002
---------------
3rd Qtr 4th Qtr 2003 2004
------- ------- ------ -----
Puts
Average price $20.00/bbl.......... 2,000 2,000 -- --
Calls
Average price $35.17/bbl.......... 9,000 9,000 -- --
Collars
Average floor price of $22.00/bbl.
Average cap price of $27.04/bbl... -- -- 2,000 --
Swaps
Average price $24.10/bbl.......... 19,000 -- -- --
Average price $24.09/bbl.......... -- 19,000 -- --
Average price $23.31/bbl.......... -- -- 14,750 --
Average price $23.02/bbl.......... -- -- -- 5,000
9
PLAINS RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Note 4--Comprehensive Income
Comprehensive income includes net income and certain items recorded directly
to Stockholders' Equity and classified as OCI. The following table reflects
comprehensive income for the three and six months ended June 30, 2002 and 2001
(in thousands of dollars):
Three Months Ended Six Months Ended
June 30, June 30,
----------------- ------------------
2002 2001 2002 2001
------- -------- -------- --------
Net Income............................................... $ 9,674 $100,102 $ 16,270 $119,068
Other Comprehensive Income (Loss)
Cumulative effect of change in accounting principle--
January 1, 2001..................................... -- -- -- 6,856
Reclassification adjustment for settled contracts..... (3,238) 71 (6,790) (733)
Change in fair value of open hedging positions........ 1,417 (773) (18,931) (6,813)
Equity in OCI changes of PAA.......................... 2,451 (293) 2,004 (1,188)
------- -------- -------- --------
Other Comprehensive Income (Loss)........................ 630 (995) (23,717) (1,878)
------- -------- -------- --------
Comprehensive Income (Loss).............................. $10,304 $ 99,107 $ (7,447) $117,190
======= ======== ======== ========
Note 5--Earnings Per Share
The following is a reconciliation of the numerators and the denominators of
the basic and diluted earnings per share computations for income from
continuing operations before the cumulative effect of accounting change for the
three and six months ended June 30, 2002 and 2001 (dollar amounts and shares in
thousands, except per share data):
For the Three Months Ended June 30,
-----------------------------------------------------------------
2002 2001
-------------------------------- --------------------------------
Per Per
Income Shares Share Income Shares Share
(Numerator) (Denominator) Amount (Numerator) (Denominator) Amount
----------- ------------- ------ ----------- ------------- ------
Income before cumulative effect
of accounting change......... $9,674 $100,102
Less: preferred stock
dividends.................... (350) (24,947)
------ --------
Income available to common
stockholders................. 9,324 23,883 $0.39 75,155 19,631 $3.83
===== =====
Effect of dilutive securities:
Convertible preferred
stock..................... 350 932 1,067 7,972
Employee stock options and
warrants.................. -- 702 -- 891
------ ------ -------- ------
Income available to common
stockholders assuming
dilution..................... $9,674 25,517 $0.38 $ 76,222 28,494 $2.68
====== ====== ===== ======== ====== =====
10
PLAINS RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Six Months Ended June 30,
-----------------------------------------------------------------
2002 2001
-------------------------------- --------------------------------
Per Per
Income Shares Share Income Shares Share
(Numerator) (Denominator) Amount (Numerator) (Denominator) Amount
----------- ------------- ------ ----------- ------------- ------
Income before cumulative effect
of accounting change......... $16,270 $121,054
Less: preferred stock
dividends.................... (700) (26,546)
------- --------
Income available to common
stockholders................. 15,570 23,759 $0.66 94,508 18,547 $5.10
===== ------ =====
Effect of dilutive securities:
Convertible preferred
stock..................... 700 932 2,666 9,349
Employee stock options and
warrants.................. -- 614 -- 861
------- ------ -------- ------
Income available to common
stockholders assuming
dilution..................... $16,270 25,305 $0.64 $ 97,174 28,757 $3.38
======= ====== ===== ======== ====== =====
The $2.0 million cumulative effect of accounting change, net of tax benefit,
recognized in the first quarter of 2001 resulted in a reduction in our basic
and diluted earnings per share for the six months ended June 30, 2001 of $0.11
and $0.07, respectively.
Note 6--Commitments and Contingencies
In connection with the sale of a portion of our interest in PAA in June
2001, we entered into a value assurance agreement with each of the purchasers
of PAA subordinated units. In the event PAA's annual distribution is less than
$1.85 per unit on its subordinated units, the value assurance agreements
require us to pay to the purchasers 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.
Also in connection with the June 2001 sale of a portion of our interest in
PAA, we entered into a separation agreement with PAA whereby, among other
things, (1) we agreed to indemnify PAA, its general partner, and its
subsidiaries against (a) any claims related to the upstream business, whenever
arising, and (b) any claims related to federal or state securities laws or the
regulations of any self-regulatory authority, or other similar claims,
resulting from alleged acts or omissions by us, our subsidiaries, PAA, or PAA's
subsidiaries occurring on or before June 8, 2001, and (2) PAA agreed to
indemnify us and our subsidiaries against any claims related to the midstream
business, whenever arising.
We, in the ordinary course of business, are a claimant and/or defendant in
various legal proceedings. Management does 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.
11
PLAINS RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Note 7--Subsequent Event
At June 30, 2002, $17.5 million was outstanding under Plains Resources'
$225.0 million senior secured revolving credit facility (the "Plains credit
facility"). At such date we were in compliance with the covenants contained in
the facility and could have borrowed the full $225.0 million available under
the facility. Plains Resources also had $267.5 million aggregate principal
amount of 10.25% Senior Subordinated Notes due 2006 (the "10.25% notes")
outstanding at June 30, 2002.
On July 3, 2002, Plains Exploration & Production Company, L.P. ("PXP", a
wholly owned subsidiary that conducts our upstream operations onshore and
offshore California and in Illinois) and Plains E&P Company (a wholly owned
subsidiary of PXP that has no material assets and was formed for the sole
purpose of being a corporate co-issuer of certain notes) issued, at an issue
price of 98.376%, $200.0 million of 8.75% Senior Subordinated Notes due 2012
(the "8.75% notes"). Also on July 3, PXP entered into a revolving credit
facility (the "PXP credit facility") of up to $300.0 million, of which $150.0
million was committed on that date. The syndication of the PXP credit facility
for the full $300.0 million, with a $225.0 million borrowing base, was
completed on July 19, 2002.
The proceeds from the 8.75% notes, $195.3 million after deducting $3.2
million in issue discount and $1.5 million in underwriting fees, and $117.6
million initially borrowed under the PXP credit facility were used to: (i)
establish a $287.0 million escrow account to redeem the 10.25% notes; (ii)
retire the $25.0 million outstanding under the Plains credit facility on July
3, 2002; and (iii) pay $0.9 million in fees related to the PXP credit facility.
Upon payment of the amount outstanding under the Plains credit facility, that
agreement was terminated. The $287.0 million escrow account to redeem the
10.25% notes consisted of: (i) the $267.5 million principal amount; (ii) a $9.1
million call premium due as a result of the early redemption of the notes; and
(iii) $10.4 million in interest accrued and payable on the redemption date. In
connection with the redemption of the 10.25% notes and the termination of the
Plains credit facility, in the third quarter of 2002 we will recognize a $10.3
million charge to income for debt extinguishment costs.
Note 8 --Consolidating Financial Statements
The following financial information presents consolidating financial
statements which include:
. the parent company only ("Parent");
. the guarantor subsidiaries on a combined basis ("Guarantor Subsidiaries");
. the nonguarantor subsidiaries on a combined basis ("Nonguarantor
Subsidiaries");
. elimination entries necessary to consolidate the Parent, the Guarantor
Subsidiaries and the Nonguarantor Subsidiaries; and
. Plains Resources Inc. on a consolidated basis.
These statements are presented because our 10.25% notes are not guaranteed
by the Nonguarantor Subsidiaries.
12
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET
(in thousands)
(unaudited)
June 30, 2002
Guarantor Nonguarantor Intercompany
Parent Subsidiaries Subsidiaries Eliminations Consolidated
--------- ------------ ------------ ------------ ------------
ASSETS
Current Assets
Cash and cash equivalents.............. $ 1,012 $ 7 $ 57 $ -- $ 1,076
Accounts receivable.................... 4,483 20,843 -- -- 25,326
Commodity hedging contracts............ -- 632 -- -- 632
Inventory.............................. -- 7,366 -- -- 7,366
Other current assets................... 631 2,686 -- -- 3,317
--------- --------- -------- --------- ---------
6,126 31,534 57 -- 37,717
--------- --------- -------- --------- ---------
Property and Equipment, at cost
Oil and natural gas properties--full
cost method........................... 242,681 744,117 -- (149) 986,649
Other property and equipment........... 2,490 1,561 -- -- 4,051
--------- --------- -------- --------- ---------
245,171 745,678 -- (149) 990,700
Less allowance for depreciation,
depletion and amortization................ (218,262) (179,779) -- (55,386) (453,427)
--------- --------- -------- --------- ---------
26,909 565,899 -- (55,535) 537,273
--------- --------- -------- --------- ---------
Investment in Subsidiaries and
Intercompany Advances..................... 577,307 (288,840) 97,215 (322,515) 63,167
--------- --------- -------- --------- ---------
Other Assets............................... 5,708 12,794 368 (451) 18,419
--------- --------- -------- --------- ---------
$ 616,050 $ 321,387 $ 97,640 $(378,501) $ 656,576
========= ========= ======== ========= =========
LIABILITIES AND
STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable and other current
liabilities........................... $ 13,989 $ 32,179 $ 469 $ (595) $ 46,042
Commodity hedging contracts............ -- 12,659 -- -- 12,659
Interest payable....................... 8,340 102 -- -- 8,442
Notes payable.......................... -- 511 -- -- 511
--------- --------- -------- --------- ---------
22,329 45,451 469 (595) 67,654
--------- --------- -------- --------- ---------
Long-Term Debt
Bank debt.............................. 17,500 -- -- -- 17,500
Subordinated debt...................... 269,325 -- -- -- 269,325
Other.................................. -- 1,022 -- -- 1,022
--------- --------- -------- --------- ---------
286,825 1,022 -- -- 287,847
--------- --------- -------- --------- ---------
Other Long-Term Liabilities................ 3,167 4,468 210 -- 7,845
--------- --------- -------- --------- ---------
Deferred Income Taxes...................... 50,465 2,557 (13,056) -- 39,966
--------- --------- -------- --------- ---------
Stockholders' Equity....................... 253,264 267,889 110,017 (377,906) 253,264
--------- --------- -------- --------- ---------
$ 616,050 $ 321,387 $ 97,640 $(378,501) $ 656,576
========= ========= ======== ========= =========
13
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET
(in thousands)
December 31, 2001
Guarantor Nonguarantor Intercompany
Parent Subsidiaries Subsidiaries Eliminations Consolidated
--------- ------------ ------------ ------------ ------------
ASSETS
Current Assets
Cash and cash equivalents........... $ 1,013 $ 13 $ 153 $ -- $ 1,179
Accounts receivable................. 3,222 16,817 -- -- 20,039
Commodity hedging contracts......... 33 23,224 -- -- 23,257
Inventory........................... -- 6,721 -- -- 6,721
Other current assets................ 294 1,233 -- -- 1,527
--------- --------- -------- --------- ---------
4,562 48,008 153 -- 52,723
--------- --------- -------- --------- ---------
Property and Equipment, at cost
Oil and natural gas properties--full
cost method....................... 241,509 700,044 -- (149) 941,404
Other property and equipment........ 2,460 1,543 -- -- 4,003
--------- --------- -------- --------- ---------
243,969 701,587 -- (149) 945,407
Less allowance for depreciation,
depletion and amortization........ (217,801) (164,795) -- (55,386) (437,982)
--------- --------- -------- --------- ---------
26,168 536,792 -- (55,535) 507,425
--------- --------- -------- --------- ---------
Investment in Subsidiaries and
Intercompany Advances............. 565,098 (267,294) 85,389 (318,567) 64,626
--------- --------- -------- --------- ---------
Other Assets........................ 4,652 19,430 383 (451) 24,014
--------- --------- -------- --------- ---------
$ 600,480 $ 336,936 $ 85,925 $(374,553) $ 648,788
========= ========= ======== ========= =========
LIABILITIES AND
STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable and other
current liabilities............ $ 10,255 $ 42,581 $ 1,059 $ -- $ 53,895
Interest payable................. 8,286 -- -- -- 8,286
Notes payable.................... -- 511 -- -- 511
--------- --------- -------- --------- ---------
18,541 43,092 1,059 -- 62,692
--------- --------- -------- --------- ---------
Long-Term Debt
Bank debt........................ 11,500 -- -- -- 11,500
Subordinated debt................ 269,539 -- -- -- 269,539
Other............................ -- 1,022 -- -- 1,022
--------- --------- -------- --------- ---------
281,039 1,022 -- -- 282,061
--------- --------- -------- --------- ---------
Other Long-Term Liabilities......... 3,013 1,413 463 -- 4,889
--------- --------- -------- --------- ---------
Deferred Income Taxes............... 43,035 19,190 (17,931) -- 44,294
--------- --------- -------- --------- ---------
Stockholders' Equity................ 254,852 272,219 102,334 (374,553) 254,852
--------- --------- -------- --------- ---------
$ 600,480 $ 336,936 $ 85,925 $(374,553) $ 648,788
========= ========= ======== ========= =========
14
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENT OF INCOME
(in thousands)
(unaudited)
Three Months Ended June 30, 2002
Guarantor Nonguarantor Intercompany
Parent Subsidiaries Subsidiaries Eliminations Consolidated
------- ------------ ------------ ------------ ------------
Revenues
Crude oil and liquids......... $ -- $46,319 $ -- $ -- $46,319
Natural gas................... -- 2,589 -- -- 2,589
------- ------- ------- -------- -------
-- 48,908 -- -- 48,908
------- ------- ------- -------- -------
Expenses
Production expenses........... -- 19,282 -- -- 19,282
General and administrative.... 1,567 2,408 7 -- 3,982
Depreciation, depletion and
amortization................ 513 7,471 -- -- 7,984
------- ------- ------- -------- -------
2,080 29,161 7 -- 31,248
------- ------- ------- -------- -------
Income (Loss) from Operations.... (2,080) 19,747 (7) -- 17,660
Other Income (Expense)
Equity in earnings of
subsidiary.................. 16,273 -- 5,256 (16,273) 5,256
Interest expense.............. -- (6,516) -- -- (6,516)
Interest and other income..... 5 17 4 -- 26
------- ------- ------- -------- -------
Income Before Income Taxes....... 14,198 13,248 5,253 (16,273) 16,426
Income tax benefit (expense):
Current................... (405) -- (180) -- (585)
Deferred.................. (4,119) (150) (1,898) -- (6,167)
------- ------- ------- -------- -------
Net Income 9,674 13,098 3,175 (16,273) 9,674
Preferred dividend
requirement................. (350) -- -- -- (350)
------- ------- ------- -------- -------
Income Attributable to Common
Shares......................... $ 9,324 $13,098 $ 3,175 $(16,273) $ 9,324
======= ======= ======= ======== =======
15
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENT OF INCOME
(in thousands)
(unaudited)
Three Months Ended June 30, 2001
Guarantor Nonguarantor Intercompany
Parent Subsidiaries Subsidiaries Eliminations Consolidated
-------- ------------ ------------ ------------ ------------
Revenues
Crude oil and liquids......... $ -- $58,001 $ -- $ -- $ 58,001
Natural gas................... -- 423 -- -- 423
-------- ------- -------- --------- --------
-- 58,424 -- -- 58,424
-------- ------- -------- --------- --------
Expenses
Production expenses........... -- 17,850 -- -- 17,850
General and administrative.... 9,387 2,092 -- -- 11,479
Depreciation, depletion and
amortization................ 1,451 5,085 49 -- 6,585
-------- ------- -------- --------- --------
10,838 25,027 49 -- 35,914
-------- ------- -------- --------- --------
Income (Loss) from
Operations..................... (10,838) 33,397 (49) -- 22,510
Other Income (Expense)
Equity in earnings of
subsidiary.................. 195,629 -- 3,755 (195,629) 3,755
Gain on PAA units............. -- -- 148,213 -- 148,213
Interest expense.............. (945) (5,882) -- -- (6,827)
Interest and other income..... (707) (136) 174 -- (669)
-------- ------- -------- --------- --------
Income Before Income Taxes and
Cumulative Effect of
Accounting Change.............. 183,139 27,379 152,093 (195,629) 166,982
Income tax benefit (expense):
Current..................... -- -- (8,449) -- (8,449)
Deferred.................... (99,768) 7,277 (51,929) 85,989 (58,431)
-------- ------- -------- --------- --------
Net Income....................... 83,371 34,656 91,715 (109,640) 100,102
Preferred dividend
requirement................. (24,947) -- -- -- (24,947)
-------- ------- -------- --------- --------
Income Attributable to
Common Shares............... $ 58,424 $34,656 $ 91,715 $(109,640) $ 75,155
======== ======= ======== ========= ========
16
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENT OF INCOME
(in thousands)
(unaudited)
Six Months Ended June 30, 2002
Guarantor Nonguarantor Intercompany
Parent Subsidiaries Subsidiaries Eliminations Consolidated
------- ------------ ------------ ------------ ------------
Revenues
Crude oil and liquids......... $ -- $ 88,121 $ -- $ -- $ 88,121
Natural gas................... -- 4,577 -- -- 4,577
------- -------- ------- -------- --------
-- 92,698 -- -- 92,698
------- -------- ------- -------- --------
Expenses
Production expenses........... -- 38,007 -- -- 38,007
General and administrative.... 2,910 5,177 14 -- 8,101
Depreciation, depletion and
amortization................ 974 14,860 -- -- 15,834
------- -------- ------- -------- --------
3,884 58,044 14 -- 61,942
------- -------- ------- -------- --------
Income (Loss) from Operations.... (3,884) 34,654 (14) -- 30,756
Other Income (Expense)
Equity in earnings of
subsidiary.................. 27,059 -- 9,606 (27,059) 9,606
Interest expense.............. -- (12,895) -- -- (12,895)
Interest and other income..... 9 36 18 -- 63
------- -------- ------- -------- --------
Income Before Income Taxes....... 23,184 21,795 9,610 (27,059) 27,530
Income tax benefit (expense):
Current..................... 2,275 -- (338) -- 1,937
Deferred.................... (9,189) (415) (3,593) -- (13,197)
------- -------- ------- -------- --------
Net Income....................... 16,270 21,380 5,679 (27,059) 16,270
Preferred dividend
requirement................. (700) -- -- -- (700)
------- -------- ------- -------- --------
Income Attributable to Common
Shares......................... $15,570 $ 21,380 $ 5,679 $(27,059) $ 15,570
======= ======== ======= ======== ========
17
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENT OF INCOME
(in thousands)
(unaudited)
Six Months Ended June 30, 2001
Guarantor Nonguarantor Intercompany
Parent Subsidiaries Subsidiaries Eliminations Consolidated
--------- ------------ ------------ ------------ ------------
Revenues
Crude oil and liquids....... $ -- $116,233 $ -- $ -- $116,233
Natural gas................. -- 423 -- -- 423
--------- -------- -------- --------- --------
-- 116,656 -- -- 116,656
--------- -------- -------- --------- --------
Expenses
Production expenses......... 2 34,028 -- -- 34,030
General and administrative.. 10,434 5,113 13 -- 15,560
Depreciation, depletion and
amortization.............. 1,362 11,924 98 -- 13,384
--------- -------- -------- --------- --------
11,798 51,065 111 -- 62,974
--------- -------- -------- --------- --------
Income (Loss) from
Operations................... (11,798) 65,591 (111) -- 53,682
Other Income (Expense)
Equity in earnings of
subsidiary................ 215,368 -- 10,591 (215,368) 10,591
Gain on PAA units........... -- -- 150,171 -- 150,171
Interest expense............ (2,266) (11,557) -- -- (13,823)
Interest and other income... (685) 423 260 -- (2)
--------- -------- -------- --------- --------
Income Before Income Taxes
and Cumulative Effect of
Accounting Change............ 200,619 54,457 160,911 (215,368) 200,619
Income tax benefit (expense):
Current..................... 1,788 -- (10,715) -- (8,927)
Deferred.................... (100,071) (3,454) (53,102) 85,989 (70,638)
--------- -------- -------- --------- --------
Income Before Cumulative Effect
of Accounting Change......... 102,336 51,003 97,094 (129,379) 121,054
Cumulative effect of
accounting change, net of
tax benefit............... -- (2,129) 143 -- (1,986)
--------- -------- -------- --------- --------
Net Income..................... 102,336 48,874 97,237 (129,379) 119,068
Preferred dividend
requirement............... (26,546) -- -- -- (26,546)
--------- -------- -------- --------- --------
Income Attributable to Common
Shares....................... $ 75,790 $ 48,874 $ 97,237 $(129,379) $ 92,522
========= ======== ======== ========= ========
18
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
(in thousands)
(unaudited)
Six Months Ended June 30, 2002
Guarantor Nonguarantor Intercompany
Parent Subsidiaries Subsidiaries Eliminations Consolidated
-------- ------------ ------------ ------------ ------------
CASH FLOWS FROM OPERATING
ACTIVITIES
Net income (loss)......................... $ 16,270 $ 21,380 $ 5,679 $(27,059) $ 16,270
Adjustments to reconcile net income to
net cash provided by operating
activities:
Depreciation, depletion, and
amortization......................... 974 14,860 -- -- 15,834
Equity in earnings of subsidiaries..... (27,059) -- (9,606) 27,059 (9,606)
Distributions from subsidiaries........ -- -- 14,140 -- 14,140
Deferred income taxes.................. 9,189 415 3,593 -- 13,197
Other.................................. 1,045 -- -- -- 1,045
Change in assets and liabilities resulting
from operating activities:
Current and other assets............... 9,474 (16,346) (96) -- (6,968)
Current and other liabilities.......... 4,471 2,368 (13,806) -- (6,967)
-------- -------- -------- -------- --------
Net cash provided by (used in) operating
activities.............................. 14,364 22,677 (96) -- 36,945
-------- -------- -------- -------- --------
CASH FLOWS FROM INVESTING
ACTIVITIES
Oil and gas properties and equipment...... (1,172) (45,889) -- -- (47,061)
Other properties and equipment............ (30) (18) -- -- (48)
-------- -------- -------- -------- --------
Net cash used in investing activities..... (1,202) (45,907) -- -- (47,109)
-------- -------- -------- -------- --------
CASH FLOWS FROM FINANCING
ACTIVITIES
Net change in long-term debt.............. 6,000 -- -- -- 6,000
Exercise of stock options................. 4,411 -- -- -- 4,411
Proceeds from issuance of preferred
stock................................... -- -- -- -- --
Preferred stock dividends paid............ (350) -- -- -- (350)
-------- -------- -------- -------- --------
Net cash provided by financing
activities.............................. 10,061 -- -- -- 10,061
-------- -------- -------- -------- --------
Net increase (decrease) in cash and cash
equivalents............................. 23,223 (23,230) (96) -- (103)
Cash and cash equivalents, beginning of
period.................................. 1,013 13 153 -- 1,179
-------- -------- -------- -------- --------
Cash and cash equivalents, end of
period.................................. $ 24,236 $(23,217) $ 57 $ -- $ 1,076
======== ======== ======== ======== ========
19
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
(in thousands)
(unaudited)
Six Months Ended June 30, 2001
Guarantor Nonguarantor Intercompany
Parent Subsidiaries Subsidiaries Eliminations Consolidated
--------- ------------ ------------ ------------ ------------
CASH FLOWS FROM OPERATING
ACTIVITIES
Net income (loss).............................. $ 102,336 $ 48,874 $ 97,237 $(129,379) $ 119,068
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation, depletion, and amortization.... 1,362 11,924 98 -- 13,384
Equity earnings in subsidiary................ (215,368) -- (10,591) 215,368 (10,591)
Distributions from subsidiary................ -- -- 17,907 -- 17,907
Gain on sale of PAA units.................... -- -- (150,171) -- (150,171)
Deferred income tax.......................... 100,071 4,200 53,102 (85,989) 71,384
Cumulative effect of accounting change....... -- 2,129 (143) -- 1,986
Change in derivative fair value.............. -- 1,227 -- -- 1,227
Other noncash items.......................... 4,925 -- -- -- 4,925
Change in assets and liabilities resulting from
operating activities:
Current and other assets..................... 10,644 (9,252) 9,875 -- 11,267
Current and other liabilities................ 3,623 (5,597) (10,708) -- (12,682)
--------- -------- --------- --------- ---------
Net cash provided by (used in) operating
activities.................................... 7,593 53,505 6,606 -- 67,704
--------- -------- --------- --------- ---------
CASH FLOWS FROM INVESTING
ACTIVITIES
Properties and equipment....................... (1,987) (60,485) -- -- (62,472)
Sale of PAA units.............................. -- -- 105,899 -- 105,899
Investment in PAA.............................. -- -- (2,763) (2,763)
--------- -------- --------- --------- ---------
Net cash used in investing activities.......... (1,987) (60,485) 103,136 -- 40,664
--------- -------- --------- --------- ---------
CASH FLOWS FROM FINANCING
ACTIVITIES
Net change in long-term debt................... (27,300) -- -- -- (27,300)
Exercise of stock options...................... 2,892 -- -- -- 2,892
Treasury stock purchases....................... (39,528) -- -- -- (39,528)
Preferred stock dividends paid................. (7,648) -- -- -- (7,648)
Dividends paid................................. 79,925 -- (79,925) -- --
Other.......................................... (68) -- -- -- (68)
--------- -------- --------- --------- ---------
Net cash provided by financing activities...... 8,273 -- (79,925) -- (71,652)
--------- -------- --------- --------- ---------
Net increase (decrease) in cash and cash
equivalents................................... 13,879 (6,980) 29,817 -- 36,716
Decrease in cash due to deconsolidation of
PAA........................................... -- -- (3,425) -- (3,425)
Cash and cash equivalents, beginning of
period........................................ 4 597 4,479 -- 5,080
--------- -------- --------- --------- ---------
Cash and cash equivalents, end of period....... $ 13,883 $ (6,383) $ 30,871 $ -- $ 38,371
========= ======== ========= ========= =========
20
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
General
The following updates information as to our financial condition provided in
our Form 10-K for the year ended December 31, 2001, and analyzes the changes in
the results of operations between the three and six month periods ended June
30, 2002 and the comparable periods in 2001. There have been no significant
changes in our business or properties during the first six months of 2002.
The following are abbreviations and definitions of certain terms commonly
used in the oil and gas industry:
Bbl One stock tank barrel, or 42 U.S. gallons liquid volume, used in
reference to oil or other liquid hydrocarbons.
BOE One stock tank barrel equivalent of oil, calculated by converting gas
volumes to equivalent oil barrels at a ratio of 6 Mcf to 1 Bbl of oil.
Differential An adjustment to the price of oil to reflect differences in the
quality and/or location of oil.
Gas Natural gas.
MBbl One thousand barrels of oil or other liquid hydrocarbons.
MBOE One thousand BOE.
Mcf One thousand cubic feet of gas.
Midstream The portion of the oil and gas industry focused on marketing,
gathering, transporting and storing oil.
MMBbl One million barrels of oil or other liquid hydrocarbons.
MMBOE One million BOE.
MMcf One million cubic feet of gas.
NYMEX New York Mercantile Exchange.
Oil Crude oil, condensate and natural gas liquids.
Upstream The portion of the oil and gas industry focused on acquiring,
exploiting, developing, exploring for and producing oil and gas.
Debt Restructuring
On July 3, 2002, Plains Exploration & Production Company, L.P., or PXP, and
Plains E&P Company (both of which are wholly owned subsidiaries) issued, at an
issue price of 98.376%, $200.0 million of 8.75% Senior Subordinated Notes due
2012, or the 8.75% notes. Also on July 3, PXP entered into a revolving credit
facility, or the PXP credit facility, of up to $300 million, of which $150.0
million was committed on that date. The syndication of the PXP credit facility
for the full $300.0 million, with a $225.0 million borrowing base, was
completed on July 19, 2002.
The proceeds from the 8.75% notes, $195.3 million after deducting issue
discount and underwriting fees, and $117.6 million initially borrowed under the
PXP credit facility were used to: (i) establish a $287.0 million escrow account
to redeem $267.5 million of outstanding 10.25% Senior Subordinated Notes, or
the 10.25% notes; (ii) retire the $25.0 million outstanding under Plains
Resources' credit facility, or the Plains credit facility, on July 3, 2002; and
(iii) pay $0.9 million in fees related to the PXP credit facility.
21
For a complete discussion of these transactions and the terms and conditions
of the 8.75% notes and the PXP credit facility, see "Liquidity and Capital
Resources--Debt".
Proposed Initial Public Offering and Spin-off of PXP
On May 22, 2002 we received a favorable private letter ruling from the
Internal Revenue Service, or IRS, stating that, for United States federal
income tax purposes, a distribution of the capital stock of PXP to our
stockholders will generally be tax-free to both us and our stockholders. We
call this proposed distribution the "spin-off." On June 21, 2002 PXP filed a
registration statement on Form S-1 with the Securities and Exchange Commission,
or SEC, for the initial public offering, or IPO, of PXP's common stock. PXP is
a wholly owned subsidiary that conducts our upstream onshore and offshore
California and Illinois operations.
Prior to completing the spin-off, we intend to seek a supplemental private
letter ruling from the IRS that the IPO will not affect our earlier ruling.
There can be no assurance that we will complete the IPO because of market, SEC
review, regulatory, consent or other external factors, or because of a change
in our business plan. If the IPO occurs, we expect the spin-off to occur within
the following twelve months. If the IPO does not occur, we may still decide to
proceed with the spin-off.
The spin-off will, among other things, generally divide our midstream and
upstream assets into two separate platforms, allow us and PXP to focus
corporate strategies and management teams for each business and simplify our
corporate structure. If the spin-off occurs, we would retain our interest in
our Florida oil and gas properties and our interest in Plains All American
Pipeline, L.P., or PAA. Also, the 8.75% notes and borrowings under the PXP
credit facility would no longer be our obligations. At the time of the spin-off
we expect that we would realign our management to reflect the separation of the
midstream and upstream assets.
We have yet to make a final determination of if and when we will implement
the spin-off. Any decision to pursue the spin-off is subject to obtaining a
number of regulatory and contractual third-party consents and permits,
including a supplemental private letter ruling from the IRS. Accordingly, we
cannot provide any assurance that the spin-off will occur.
22
Results of Operations
The following tables reflect our oil and gas production and sales volumes,
the components of our oil and gas revenues and set forth our revenues and costs
and expenses on a BOE basis:
Three Months Ended Six Months Ended
June 30, June 30,
---------------- ----------------
2002 2001 2002 2001
------- ------- ------- -------
Production Volumes
Oil and liquids (MBbls)............... 2,310 2,269 4,590 4,444
Natural Gas (MMcf).................... 842 882 1,719 1,627
MBOE.................................. 2,450 2,416 4,876 4,715
Sales Volumes
Oil and liquids (MBbls)............... 2,282 2,156 4,531 4,463
Natural Gas (MMcf).................... 842 882 1,719 1,627
MBOE.................................. 2,423 2,303 4,818 4,734
Daily Average Sales Volumes
Total
Oil and liquids (Bbls)............ 25,082 23,693 25,034 24,657
Natural Gas (Mcf)................. 9,252 9,695 9,496 8,989
BOE............................... 26,624 25,309 26,617 26,155
Oil and Liquids (Bbls)
Onshore California................ 17,185 15,938 16,702 15,330
Offshore California............... 3,131 3,490 3,429 3,654
Illinois.......................... 2,540 2,705 2,590 2,749
Florida........................... 2,226 1,560 2,313 2,924
------- ------- ------- -------
25,082 23,693 25,034 24,657
======= ======= ======= =======
Natural Gas (Mcf)
Onshore California................ 9,252 9,695 9,496 8,989
======= ======= ======= =======
Unit Economics (in dollars)
Average Liquids Sales Price ($/Bbl)
Average NYMEX..................... $ 26.27 $ 27.98 $ 24.02 $ 28.40
Hedging gain (loss)............... (1.76) (1.54) (0.16) (1.66)
Differential...................... (4.22) (5.26) (4.42) (5.97)
------- ------- ------- -------
Net realized...................... $ 20.29 $ 21.18 $ 19.44 $ 20.77
======= ======= ======= =======
Average Gas Sales Price ($/Mcf)....... $ 3.07 $ 14.00 $ 2.66 $ 14.45
Average Sales Price per BOE........... $ 20.18 $ 25.19 $ 19.24 $ 24.55
Average Production Costs per BOE...... (7.96) (7.75) (7.89) (7.19)
------- ------- ------- -------
Gross Margin per BOE.................. 12.22 17.44 11.35 17.36
G&A per BOE(1)........................ (1.31) (1.62) (1.39) (1.42)
------- ------- ------- -------
Gross Profit per BOE.................. $ 10.91 $ 15.82 $ 9.96 $ 15.94
======= ======= ======= =======
DD&A per BOE (oil and gas properties). $ 3.10 $ 2.64 $ 3.10 $ 2.64
- --------
(1) Excludes costs associated with corporate reorganization and noncash
compensation expense.
23
Comparison of three months ended June 30, 2002 to three months ended June 30,
2001
Operating revenues
Our operating revenues decreased 16%, or $9.5 million, to $48.9 million for
the three months ended June 30, 2002 from $58.4 million for the three months
ended June 30, 2001. The decrease was primarily due to lower realized prices
for oil and gas that reduced revenues by $12.2 million. Higher volumes
increased revenues by $2.7 million.
Our daily oil sales volumes increased 6%, or 1.4 MBbls, to 25.1 MBbls per
day for the three months ended June 30, 2002 from 23.7 MBbls for the three
months ended June 30, 2001. Our daily gas sales volumes decreased 4%, or 0.4
MMcf, to 9.3 MMcf per day for the three months ended June 30, 2002 from 9.7
MMcf per day for the three months ended June 30, 2001. On an as produced basis,
volumes increased 1%. Production increases were primarily attributable to the
continuing development of our onshore California properties.
Our average realized price for oil and natural gas liquids decreased 4%, or
$0.89, to $20.29 per Bbl for the three months ended June 30, 2002 from $21.18
per Bbl for the three months ended June 30, 2001. The average NYMEX oil price
decreased 6%, or $1.71, to $26.27 per Bbl for the three months ended June 30,
2002 from $27.98 per Bbl for the three months ended June 30, 2001. The NYMEX
decrease was partially offset by a $1.04 per Bbl improvement in location and
quality differentials. Hedging losses averaged $1.76 per Bbl for the three
months ended June 30, 2002 as compared to $1.54 per Bbl for the same period in
2001. The average realized price for gas decreased 78%, or $10.93, to $3.07 per
Mcf for the three months ended June 30, 2002 from $14.00 per Mcf in 2001. Gas
prices were unusually high in 2001, particularly in California.
Production expenses
Our production expenses increased 8%, or $1.4 million, to $19.3 million for
the three months ended June 30, 2002 from $17.9 million for the three months
ended June 30, 2001. On a per unit basis, production expenses increased 3%, or
$0.21, to $7.96 per BOE for the three months ended June 30, 2002 from $7.75 per
BOE for the three months ended June 30, 2001, primarily due to higher
electricity costs in California.
General and administrative expense
Our general and administrative expense, or G&A expense, decreased 65%, or
$7.5 million, to $4.0 million for the three months ended June 30, 2002 from
$11.5 million for the three months ended June 30, 2001. G&A expense for 2001
included $7.8 million of nonrecurring noncash compensation and other costs
incurred in conjunction with our strategic reorganization that was completed in
June 2001.
Depreciation, depletion and amortization
Our depreciation, depletion and amortization, or DD&A, expense increased
21%, or $1.4 million, to $8.0 million for the three months ended June 30, 2002
from $6.6 million for the three months ended June 30, 2001. An increase in the
oil and gas DD&A rate to $3.10 per BOE for the three months ended June 30, 2002
from $2.64 per BOE for the three months ended June 30, 2001 was primarily due
to increased estimated future development costs of our proved reserves.
Equity in earnings of PAA
Our equity in earnings of PAA increased 40%, or $1.5 million, to $5.3
million for the three months ended June 30, 2002 from $3.8 million for the
three months ended June 30, 2001. PAA reported earnings of $17.0 million for
the three months ended June 30, 2002 compared to $7.1 million for the
24
three months ended June 30, 2001. PAA's earnings for 2001 were reduced by $5.6
million in noncash compensation expenses primarily related to the vesting of
partnership units in connection with our strategic reorganization. Our
ownership interest in PAA in 2002 was approximately 29% compared to
approximately 54% in 2001.
Gain on PAA units
Our 2001 gain related to the sale of a portion of our investment in PAA in
connection with our strategic reorganization and PAA's May 2001 equity offering.
Interest expense
Our interest expense decreased 5%, or $0.3 million, to $6.5 million for the
three months ended June 30, 2002 from $6.8 million for the three months ended
June 30, 2001, reflecting lower amounts owed on our revolving credit facility.
Income tax expense
Our income tax expense decreased $60.1 million to $6.8 million for the three
months ended June 30, 2002 from $66.9 million for the three months ended June
30, 2001. The decrease was primarily due to decreases in pre-tax income,
partially offset by an increase in our effective tax rate. Our effective tax
rate was 40.9% for the three months ended June 30, 2002 as compared to 40.1%
for the three months ended June 30, 2001.
Comparison of six months ended June 30, 2002 to six months ended June 30, 2001
Operating revenues
Our operating revenues decreased 21%, or $24.0 million, to $92.7 million for
the six months ended June 30, 2002 from $116.7 million for the six months ended
June 30, 2001. The decrease was primarily due to lower realized prices for oil
and gas that reduced revenues by $25.5 million. Higher volumes increased
revenues by $1.5 million.
Our daily oil sales volumes increased 2%, or 0.4 MBbls, to 25.0 MBbls per
day for the six months ended June 30, 2002 from 24.6 MBbls for the six months
ended June 30, 2001. Our daily gas sales volumes increased 6%, or 0.5 MMcf, to
9.5 MMcf per day for the six months ended June 30, 2002 from 9.0 MMcf for the
six months ended June 30, 2001. Production increases were primarily
attributable to the continuing development of our onshore California properties.
Our average realized price for oil and natural gas liquids decreased 6%, or
$1.33, to $19.44 per Bbl for the six months ended June 30, 2002 from $20.77 per
Bbl for the six months ended June 30, 2001. The average NYMEX oil price
decreased 15%, or $4.38, to $24.02 per Bbl for the six months ended June 30,
2002 from $28.40 per Bbl for the six months ended June 30, 2001. The NYMEX
decrease was partially offset by a 90%, or $1.50 decrease in our hedging loss
per Bbl, from $1.66 per Bbl for the six months ended June 30, 2001 to $0.16 per
Bbl for the six months ended June 30, 2002, as well as a 26%, or $1.55 per Bbl
improvement in location and quality differentials over the same periods. The
average realized price for gas decreased 82%, or $11.79, to $2.66 per Mcf for
the six months ended June 30, 2002 from $14.45 per Mcf in 2001. Gas prices were
unusually high in 2001, particularly in California.
Production expenses
Our production expenses increased 12%, or $4.0 million, to $38.0 million for
the six months ended June 30, 2002 from $34.0 million for the six months ended
June 30, 2001. On a per unit basis,
25
production expenses increased 10%, or $0.70 per BOE, to $7.89 per BOE for the
six months ended June 30, 2002 from $7.19 per BOE for the six months ended June
30, 2001. Production expenses for 2001 were reduced by approximately $0.46 per
BOE as a result of nonrecurring credits (primarily the sale of certain
California emissions credits). Excluding these credits, production expenses
increased 3% per BOE during the period, primarily due to higher electricity
costs in California.
General and administrative expense
G&A expense decreased 48%, or $7.5 million, to $8.1 million for the six
months ended June 30, 2002 from $15.6 million for the six months ended June 30,
2001. G&A expense for 2002 includes $0.6 million of costs related to our 2001
strategic reorganization and our proposed spinoff. G&A expense for 2001
includes $8.8 million of nonrecurring noncash compensation and other costs
incurred in conjunction with our strategic reorganization that was completed in
June 2001.
Depreciation, depletion and amortization
DD&A increased 18%, or $2.4 million, to $15.8 million for the six months
ended June 30, 2002 from $13.4 million for the six months ended June 30, 2001.
An increase in the oil and gas DD&A rate to $3.10 per BOE for the six months
ended June 30, 2002 from $2.64 per BOE for the six months ended June 30, 2001
was primarily due to increased estimated future development costs of our proved
reserves.
Equity in earnings of Plains All American Pipeline, L.P. (PAA)
Our equity in earnings of PAA decreased 9%, or $1.0 million, to $9.6 million
for the six months ended June 30, 2002 from $10.6 million for the six months
ended June 30, 2001. PAA reported earnings of $31.2 million for the six months
ended June 30, 2002 compared to $20.1 million for the six months ended June 30,
2001. PAA's earnings for 2001 were reduced by $5.7 million in noncash
compensation expenses primarily related to the vesting of partnership units in
connection with our strategic reorganization. Our ownership interest in PAA in
2002 was approximately 29% compared to approximately 54% in 2001.
Gain on PAA units
Our 2001 gain related to the sale of a portion of our investment in PAA in
connection with our June 2001 strategic reorganization and PAA's May 2001
equity offering.
Interest expense
Our interest expense decreased 7%, or $0.9 million, to $12.9 million for the
six months ended June 30, 2002 from $13.8 million for the six months ended June
30, 2001, reflecting lower amounts owed on our revolving credit facility and
lower interest rates.
Income tax expense
Our income tax expense decreased $68.3 million to $11.3 million for the six
months ended June 30, 2002 from $79.6 million for the six months ended June 30,
2001. The decrease was primarily due to a decrease in pre-tax income, partially
offset by an increase in our effective tax rate. Our effective tax rate was
40.9% for the six months ended June 30, 2002 as compared to 39.7% for the six
months ended June 30, 2001. Current income tax expense for the first six months
of 2002 includes a benefit of approximately $2.9 million representing taxes
paid in 2001 that will be refunded to us under terms of recent legislation.
Such legislation allows us to offset 100% of alternative minimum taxable income
with net operating loss carryforwards ("NOL's") for 2001 and 2002. Previously,
we could only
26
offset 90% of AMT income with NOL's. The current income tax expense 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.
Liquidity and Capital Resources
General
Cash generated from our upstream operations, PAA distributions and the PXP
credit facility are our primary sources of liquidity. We believe that we have
sufficient liquid assets, cash from operations and borrowing capacity under the
PXP credit facility to meet our short term normal recurring operating needs,
debt service obligations, contingencies and anticipated capital expenditures.
We also believe that we have sufficient liquid assets, cash from operations and
borrowing capacity under our credit facility to meet our long term normal
recurring operating needs, contingencies and anticipated capital expenditures.
We expect capital expenditures for the remainder of 2002 to be in the range
of $30 to $32 million, which will be funded by cash generated by operations and
our revolving credit facility.
In the first six months of 2002 we received cash distributions from PAA of
$14.1 million, including $1.0 million for our 44% interest in the general
partner. Based on the $0.5375 per unit distribution recently declared by PAA,
the distribution we will receive in the third quarter of 2002 will be
approximately $7.4 million, including $0.6 million for our 44% interest in the
general partner.
Cash provided by operating activities for the first six months of 2002
totaled $36.9 million. Investing activities consisted of capital expenditures
of $47.1 million. Cash provided by financing activities included $6.0 million
in net borrowings under our revolving credit facility, $4.4 million in proceeds
from the exercise of stock options, and ($0.4) million in preferred stock
dividends. Cash decreased by $0.1 million during the period.
Debt
At June 30, 2002, $17.5 million was outstanding under the Plains credit
facility. At such date we were in compliance with the covenants contained in
the facility and could have borrowed the full $225.0 million available under
the facility. An aggregate $267.5 million principal amount of the 10.25% notes
was outstanding at June 30, 2002.
On July 3, 2002, PXP and Plains E&P Company (a wholly owned subsidiary of
PXP that has no material assets and was formed for the sole purpose of being a
corporate co-issuer of certain notes) issued the 8.75% notes, at an issue price
of 98.376%. Also on July 3, PXP entered into the PXP credit facility, of which
$150.0 million was committed on that date. The syndication of the PXP credit
facility for the full $300.0 million, with a $225.0 million borrowing base, was
completed on July 19, 2002.
The proceeds from the 8.75% notes, $195.3 million after deducting $3.2
million in issue discount and $1.5 million in underwriting fees, and $117.6
million initially borrowed under the PXP credit facility were used to: (i)
establish a $287.0 million escrow account to redeem the 10.25% notes; (ii)
retire the $25.0 million outstanding under the Plains credit facility on July
3, 2002; and (iii) pay $0.9 million in fees related to the PXP credit facility.
Upon payment of the amount outstanding under the Plains credit facility, that
agreement was terminated. The $287.0 million escrow account to redeem the
10.25% notes consisted of: (i) the $267.5 million principal amount; (ii) a $9.1
million call premium due as a result of the early redemption of the notes; and
(iii) $10.4 million in interest accrued and payable on the redemption date. In
connection with the redemption of the 10.25% notes and the termination of the
Plains credit facility, in the third quarter of 2002 we will recognize a $10.3
million charge to income for debt extinguishment costs.
27
The 8.75% notes are unsecured general obligations of PXP and are
subordinated in right of payment to all existing and future senior indebtedness
and are guaranteed on a senior subordinated basis by PXP's existing and future
domestic restricted subsidiaries. Trade payables are not senior indebtedness.
The indenture governing the 8.75% notes contains covenants that limit PXP's
ability, as well as the ability of PXP's subsidiaries, among other things, to
incur additional indebtedness, make certain investments, make restricted
payments, sell assets, enter into agreements containing dividends and other
payment restrictions affecting subsidiaries, enter into transactions with
affiliates, create liens, merge, consolidate and transfer assets and enter into
different lines of business. In the event of a Change of Control, as defined in
the indenture, PXP will be required to make an offer to repurchase the 8.75%
notes at 101% of the principal amount thereof, plus accrued and unpaid interest
to the date of the repurchase. The indenture governing the 8.75% notes will
permit the spin-off and the spin-off will not, in itself, constitute a change
of control for purposes of the indenture.
The 8.75% notes are not redeemable until July 1, 2007. On or after that date
they are redeemable, at our option, at 104.375% of the principal amount for the
twelve-month period ending June 30, 2008, at 102.917% of the principal amount
for the twelve-month period ending June 30, 2009, at 101.458% of the principal
amount for the twelve-month period ending June 30, 2010 and at 100% of the
principal amount thereafter. In each case, accrued interest is payable to the
date of redemption.
The PXP credit facility provides for a borrowing base of $225.0 million that
will be reviewed every six months, with the lenders and PXP each having the
right to one annual interim unscheduled redetermination, and adjusted based on
PXP's oil and gas properties, reserves, other indebtedness and other relevant
factors, and matures in 2005. Additionally, the credit facility contains a
$30.0 million sub-limit on letters of credit. To secure borrowings, PXP pledged
100% of the shares of stock of its domestic subsidiaries and mortgages that
secure at least 80% of the total present value of its domestic oil and gas
properties.
Amounts borrowed under the PXP credit facility bear an annual interest rate,
at PXP's election, equal to either: (i) the Eurodollar rate plus from 1.375% to
1.75%; or (ii) the greater of (1) the prime rate, as determined by JPMorgan
Chase Bank, (2) the certificate of deposit rate, plus 1.0%, or (3) the federal
funds rate, plus 0.5%; plus an additional 0.125% to 0.5% for each of (1)-(3).
The amount of interest payable on outstanding borrowings is based on (1) the
utilization rate as a percentage of the total amount of funds borrowed under
the credit facility to the borrowing base and (2) PXP's long-term debt rating.
Commitment fees and letter of credit fees under the PXP credit facility are
based on the utilization rate and long-term debt rating. Commitment fees range
from 0.375% to 0.5% of the unused portion of the borrowing base. Letter of
credit fees range from 1.375% to 1.75%. The issuer of any letter of credit
receives an issuing fee of 0.125% of the undrawn amount. PXP's domestic
subsidiaries unconditionally guarantee payment of borrowings under the PXP
credit facility.
The PXP credit facility contains negative covenants that limit PXP's
ability, as well as the ability of PXP's subsidiaries, among other things, to
incur additional debt, pay dividends on stock, make distributions of cash or
property, change the nature of their business or operations, redeem stock or
redeem subordinated debt, make investments, create liens, enter into leases,
sell assets, sell capital stock of subsidiaries, create subsidiaries, guarantee
other indebtedness, enter into agreements that restrict dividends from
subsidiaries, enter into certain types of swap agreements, enter into gas
imbalance or take-or-pay arrangements, merge or consolidate and enter into
transactions with affiliates. In addition, the PXP credit facility requires PXP
to maintain a current ratio (which includes amounts available under the PXP
credit facility) of at least 1.0 to 1.0 and a ratio of earnings before
interest, depreciation, depletion, amortization and income taxes to total debt
of no more than 4.5 to 1.0. The PXP credit facility will permit the spin-off
and the spin-off will not, in itself, constitute a change of control for
purposes of the facility.
28
Investment in PAA
As of June 30, 2002, our aggregate ownership interest in PAA was
approximately 29%, which was comprised of (1) a 44% interest in the general
partner of PAA, (2) 45%, or approximately 4.5 million, of the subordinated
units and (3) 24%, or approximately 7.9 million, of the common units, including
approximately 1.3 million class B common units. Based on PAA's current annual
distribution rate of $2.15 per unit, we would receive an annual distribution
from PAA of approximately $29.7 million.
Commitments and Contingencies
In exchange for the significant value we received for the PAA subordinated
units (which are subordinated in right to distributions from PAA and are not
publicly traded) we sold in June 2001 at a price relative to the then current
market price of the publicly traded common units, we entered into a value
assurance agreement with each of the purchasers of the subordinated units. In
the event PAA's annual distribution on its subordinated units is less than
$1.85 per unit, the value assurance agreements require us to pay to the
purchasers 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.
In connection with the June 2001 sale of a portion of our interest in PAA we
entered into a separation agreement with PAA whereby, among other things, (1)
we agreed to indemnify PAA, its general partner, and its subsidiaries against
(a) any claims related to the upstream business, whenever arising, and (b) any
claims related to federal or state securities laws or the regulations of any
self-regulatory authority, or other similar claims, resulting from alleged acts
or omissions by us, our subsidiaries, PAA, or PAA's subsidiaries occurring on
or before June 8, 2001, and (2) PAA agreed to indemnify us and our subsidiaries
against any claims related to the midstream business, whenever arising.
At June 30, 2002, the aggregate amounts of contractually obligated payment
commitments for the next five years are as follows (in thousands):
2002 2003 2004 2005 2006 Thereafter
---- ------ ------ ------ -------- ----------
Long-term debt.. $511 $2,699 $9,261 $6,563 $267,450 $--
Operating leases 308 606 595 573 143 --
---- ------ ------ ------ -------- ---
$819 $3,305 $9,856 $7,136 $267,593 $--
==== ====== ====== ====== ======== ===
The long-term debt amounts consist principally of amounts due under the
Plains credit facility and the 10.25% notes, both of which were retired in
connection with our July 2002 financing transactions.
Although we maintain an inspection program designed to prevent and, as
applicable, to detect and address releases of crude oil into the environment
from our upstream operations, we may experience such releases in the future, or
discover releases that were previously unidentified. Damages and liabilities
incurred due to any future environmental releases from our assets may
substantially affect our business.
We, in the ordinary course of business, are a claimant and/or defendant in
various legal proceedings. Management does 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.
29
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 and
their effect on certain of our accounting policies are discussed below.
Commodity pricing and risk management activities
Prices for oil and gas have historically been volatile. Decreases in oil and
gas prices from current levels will adversely affect our revenues, results of
operations, cash flows and proved reserves. If the industry experiences
significant prolonged future price decreases, this could be materially adverse
to our operations and our ability to fund planned capital expenditures.
Periodically, we enter into hedging arrangements relating to a portion of
our oil production to achieve a more predictable cash flow, as well as to
reduce our exposure to adverse price fluctuations. Hedging instruments used are
typically fixed price swaps and collars and purchased puts and calls. While the
use of these types of hedging instruments limits our downside risk to adverse
price movements, we are subject to a number of risks, including instances in
which the benefit to revenues is limited when commodity prices increase. For a
further discussion concerning our risks related to oil and gas prices and our
hedging programs, see "--Quantitative and Qualitative Disclosures About Market
Risks."
Write-downs under full cost ceiling test rules
Under the SEC's full cost accounting rules we review the carrying value of
our proved oil and gas properties each quarter. Under these rules, capitalized
costs of proved oil and gas properties (net of accumulated depreciation,
depletion and amortization, and deferred income taxes) may not exceed a
"ceiling" equal to the standardized measure (including the effect of any
related hedging activities); plus the lower of cost or fair value of unproved
properties included in the costs being amortized (net of related tax effects).
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 and require a write-down if our capitalized costs exceed this
"ceiling," even if prices declined for only a short period of time. We have had
no write-downs due to these ceiling test limitations since 1998. Given the
volatility of oil and gas prices, it is likely that our estimate of discounted
future net revenues from proved oil and gas reserves will change in the near
term. If oil and gas prices decline significantly in the future, even if only
for a short period of time, write-downs of our oil and gas properties could
occur. Write-downs required by these rules do not directly impact our cash
flows from operating activities.
Oil and gas reserves
The proved reserve information included in our Form 10-K is based on
estimates prepared by outside engineering firms. Estimates prepared by others
may be higher or lower than these estimates. Because these estimates depend on
many assumptions, all of which may substantially differ from actual results,
reserve estimates may be different from the quantities of oil and gas that are
ultimately recovered. In addition, results of drilling, testing and production
after the date of an estimate may justify material revisions to the estimate.
You should not assume that the present value of future net cash flows is the
current market value of our estimated proved oil and gas reserves. In
accordance with SEC requirements, we base the estimated discounted future net
revenues from proved reserves on prices and costs on the date of the estimate.
Actual future prices and costs may be materially higher or lower than the
prices and costs as of the date of the estimate.
30
Our rate of recording DD&A is dependent upon our estimate of proved
reserves. If the estimates of proved reserves decline, the rate at which we
record DD&A expense increases, reducing our net income. This decline may result
from lower market prices, which may make it uneconomic to drill for and produce
higher cost fields. In addition, the decline in proved reserve estimates may
impact the outcome of the "ceiling" test discussed above.
Operating risks and insurance coverage
Our operations are subject to all of the risks normally incident to the
exploration for and the production of oil and gas, including blowouts,
cratering, oil spills and fires, each of which could result in damage to or
destruction of oil and gas wells, production facilities or other property, or
injury to persons. Our operations in California, including transportation of
oil by pipelines within the city and county of Los Angeles, are especially
susceptible to damage from earthquakes and involve increased risks of personal
injury, property damage and marketing interruptions because of the population
density of the area. Although we maintain insurance coverage considered to be
customary in the industry, we are not fully insured against some risks,
including earthquake risk in California, either because insurance is not
available or because of high premium costs. The occurrence of a significant
event that is not fully insured against could have a material adverse effect on
our financial position. Our insurance does not cover every potential risk
associated with operating our pipelines, including the potential loss of
significant revenues. Consistent with insurance coverage generally available to
the industry, our insurance policies provide limited coverage for losses or
liabilities relating to pollution, with broader coverage for sudden and
accidental occurrences.
Environmental matters
As an owner or lessee and operator of oil and gas properties, we are subject
to various federal, state, and local laws and regulations relating to discharge
of materials into, and protection of, the environment. These laws and
regulations may, among other things, impose liabilities on us for the cost of
pollution clean-up resulting from operations, subject us to liability for
pollution damages, and require suspension or cessation of operations in
affected areas. We maintain insurance coverage, which we believe is customary
in the industry, although we are not fully insured against all environmental
risks. We have established policies for continuing compliance with
environmental laws and regulations and have made and will continue to make
expenditures in our efforts to comply with these requirements, which we believe
are necessary business costs in the oil and gas industry.
Although we obtained environmental studies on our properties in California,
Florida and the Illinois Basin, and we believe that these properties have been
operated in accordance with standard oil field practices, certain of the fields
have been in operation for over 90 years, and current or future federal, state
and local environmental laws and regulations may require substantial
expenditures to remediate our properties or otherwise comply with these rules
and regulations. While we do not believe that the cost of remediation and other
compliance with current federal, state or local environmental laws and
regulations will have a material adverse effect on our capital expenditures,
results of operations or competitive position; there is no assurance that
changes in or additions to these laws or regulations will not have such an
impact.
Consistent with normal industry practices, substantially all of our oil and
gas leases require that, upon termination of economic production, the working
interest owners plug and abandon non-producing wellbores, remove tanks,
production equipment and flow lines and restore the wellsite. We have estimated
that the cost to perform these tasks is currently approximately $17.0 million,
net of salvage value and other considerations. These estimated amortized costs
are included in expenses through the unit-of-production method as a component
of accumulated DD & A. Results from operations for 2001, 2000 and 1999 each
include $0.5 million of expense associated with these estimated future costs.
31
Recent Accounting Pronouncements
In April 2002, Statement of Accounting Standards ("SFAS") No. 145,
"Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement
No. 13, and Technical Corrections," was issued. SFAS 145 rescinds SFAS 4 and
SFAS 64 related to classification of gains and losses on debt extinguishment
such that most debt extinguishment gains and losses will no longer be
classified as extraordinary. SFAS 145 also amends SFAS 13 with respect to
sales-leaseback transactions. The provisions of SFAS 145 with respect to
sales-leaseback transactions have no effect on our financials. As a result of
the provisions of SFAS 145 with respect to debt extinguishments, the $10.3
million of debt extinguishment costs related to our recent refinancing of
certain debt instruments will not be classified as an extraordinary item in our
statement of income.
In July 2002, SFAS No. 146, "Accounting For Costs Associated with Exit or
Disposal Activities" was issued. SFAS 146 is effective for exit or disposal
activities initiated after December 31, 2002 and does not require previously
issued financial statements to be restated. We will account for exit or
disposal activities initiated after December 31, 2002 in accordance with the
provisions of SFAS 146.
Quantitative and Qualitative Disclosures About Market Risk
We are exposed to various market risks, including volatility in oil and gas
commodity prices and interest rates. Although we have routinely hedged a
substantial portion of our crude oil production and intend to continue this
practice, substantial future crude oil price declines would adversely affect
our overall results, and therefore our liquidity. Furthermore, low crude oil
prices could affect our ability to raise capital on favorable terms. Decreases
in the prices of crude oil and natural gas have had, and could have in the
future, an adverse effect on the carrying value of our proved reserves and our
revenues, profitability and cash flow.
To manage our exposure, we monitor 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 that would expose us to price risk. Substantially all of our
derivative contracts are exchanged or traded with major financial institutions
and the risk of credit loss is considered remote.
Derivative instruments are accounted for in accordance with Statement of
Financial Accounting Standards ("SFAS") No. 133 "Accounting for Derivative
Instruments and Hedging Activities" as amended by SFAS 137 and SFAS 138 ("SFAS
133"). Under 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
unrealized gain or loss on the derivative is deferred in accumulated Other
Comprehensive Income ("OCI"), a component of Stockholders' Equity. At June 30,
2002 all open positions qualified for hedge accounting.
Gains and losses on crude oil hedging instruments related to OCI and
adjustments to carrying amounts on hedged volumes are included in oil and gas
revenues in the period that the related volumes are delivered. Gains and losses
on crude oil hedging instruments representing hedge ineffectiveness, which is
measured on a quarterly basis, are included in oil and gas revenues in the
period in which they occur.
We utilize various derivative instruments to hedge our exposure to price
fluctuations on crude oil sales. The derivative instruments consist primarily
of cash-settled crude oil option and swap contracts entered into with financial
institutions. We do not currently have any natural gas hedges. We also utilize
interest rate swaps to manage the interest rate exposure on our long-term debt.
32
During the first six months of 2002 gains of $6.8 million were relieved from
OCI and the fair value of open positions decreased $18.9 million. At June 30,
2002, the unrealized loss on our derivatives contracts included in OCI was $9.1
million. The related assets and liabilities were included in current assets and
liabilities ($0.6 million and $12.7 million, respectively), other assets and
liabilities ($0.6 million and $3.0 million, respectively), and deferred income
taxes (tax benefit of $6.3 million). Additionally, OCI includes our $0.3
million net of tax equity in the unrealized OCI losses of PAA. As of June 30,
2002, $7.6 million of deferred net losses on derivative instruments recorded in
OCI are expected to be reclassified to earnings during the next twelve-month
period.
Commodity Price Risk. At July 31, 2002 we had the following open crude oil
hedge positions (barrels per day):
Barrels Per Day
----------------------------
2002
---------------
3rd Qtr 4th Qtr 2003 2004
------- ------- ------ -----
Puts
Average price $20.00/bbl.......... 2,000 2,000 -- --
Calls
Average price $35.17/bbl.......... 9,000 9,000 -- --
Collars
Average floor price of $22.00/bbl.
Average cap price of $27.04/bbl... -- -- 2,000 --
Swaps
Average price $24.20/bbl.......... 19,663 -- -- --
Average price $24.22/bbl.......... -- 20,000 -- --
Average price $23.36/bbl.......... -- -- 15,250 --
Average price $23.02/bbl.......... -- -- -- 5,000
These positions provide for us to receive, for the six months ended December
31, 2002 an average minimum NYMEX price of approximately $23.82 per Bbl on
21,832 barrels per day with full upside participation above $20.00 per Bbl on
9% of those hedged barrels, and upside participation above $35.17 per Bbl on
50% of those hedged barrels. For example, if the NYMEX index averages $20.00
during the remainder of 2002, we will receive $23.82 per Bbl; if the NYMEX
index averages $25.00 per Bbl, we will receive $24.28 per Bbl if the NYMEX
index averages $30.00 per Bbl, we will receive $24.74 per Bbl; and if the NYMEX
index average were to fall to $15.00 per Bbl we would receive $23.82 per Bbl,
all on the hedged barrels. For 2003, we have entered into various arrangements
that provide for us to receive an average minimum NYMEX price of $23.20 per
barrel on 17,250 barrels per day with upside participation to $27.04 per Bbl on
12% of the hedged barrels. For 2004, we have entered into various arrangements
that provide for us to receive an average fixed NYMEX price of $23.02 per Bbl
on 5,000 barrels per day, regardless of the NYMEX index average. Location and
quality differentials attributable to our properties and the cost of the hedges
are not included in the foregoing prices. Because of the quality and location
of our crude oil production, these adjustments will reduce our net price per
barrel.
The agreements provide for monthly cash settlement based on the differential
between the agreement price and the actual NYMEX price. Gains or losses are
recognized in the month of related production and are included in crude oil and
natural gas sales revenues. Such contracts resulted in decreases in revenues of
$0.7 million and $7.4 million in the first six months of 2002 and 2001,
respectively. The fair value of outstanding derivative commodity instruments at
June 30, 2002 was ($14.5) million, and a 10% decrease in the forward NYMEX
price curve would result in a $26.0 million increase in such fair value.
33
The contract counterparties for our current derivative commodity contracts
are all major financial institutions with Standard & Poor's ratings of A or
better. Two of the financial institutions are participating lenders in the PXP
credit facility, with one such counterparty holding contracts that represent
approximately 28% of the fair value of all open positions at July 31, 2002.
Our management intends to continue to maintain hedging arrangements for a
significant portion of our production. These contracts may expose us to the
risk of financial loss in certain circumstances. Our hedging arrangements
provide us protection on the hedged volumes if crude oil prices decline below
the prices at which these hedges are set, but ceiling prices in our hedges may
cause us to receive less revenue on the hedged volumes than we would receive in
the absence of hedges.
Interest Rate Risk. Our debt instruments are sensitive to market
fluctuations in interest rates. Interest rate swaps are used to hedge
underlying debt obligations. These instruments hedge specific debt issuances
and qualify for hedge accounting. The interest rate differential is reflected
as an adjustment to interest expense over the life of the instruments. At June
30, 2002, we had an interest rate swap for an aggregate notional principal
amount of $7.5 million, for which we would pay approximately $0.1 million if
such arrangement were terminated as of such date. The swap expires in October
2004 and fixes the interest rate on $7.5 million of borrowing under the PXP
credit facility at 3.9% plus the LIBOR margin set forth in our credit facility.
Forward-Looking Statements and Associated Risks
This report includes forward-looking statements within the meaning of
Section 27A of the Securities Act, Section 21E of the Securities Exchange Act
of 1934 and the Private Securities Litigation Reform Act of 1995. We have based
these forward-looking statements 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
"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:
. uncertainties inherent in the exploration for and development and
production of oil and gas and in estimating reserves;
. unexpected future capital expenditures (including the amount and nature
thereof);
. impact of oil and gas price fluctuations;
. the effects of competition;
. the success of our risk management activities;
. the availability (or lack thereof) of acquisition or combination
opportunities;
. the impact of current and future laws and governmental regulations;
. environmental liabilities that are not covered by an indemnity or
insurance, and
. general economic, market or business conditions.
All forward-looking statements are made as of the date hereof, and you
should not rely on these statements without also considering the risks and
uncertainties associated with these statements and our business that are
addressed 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.
34
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. Management does 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.
Item 2--Changes in Securities and Use of Proceeds.
On July 3, 2002, PXP and Plains E&P Company (both of which are wholly-owned
subsidiaries of ours) issued, at an issue price of 98.376%, $200.0 million of
8.75% senior subordinated notes due 2012, and such issuance was exempt from the
registration requirements of the Securities Act of 1933 pursuant to Rule 144A
promulgated thereunder. Also on July 3, PXP entered into a revolving credit
facility of up to $300.0 million.
The proceeds from the 8.75% notes and borrowings under the PXP credit
facility were used to, among other things, redeem and make open market
purchases of all of our outstanding 10.25% senior subordinated notes due 2006.
As a result, all of 10.25% notes were retired by August 2, 2002.
Item 4--Submission of Matters to a Vote of Security Holders
The following items were presented for approval to stockholders of record on
March 22, 2002 at the Company's 2002 annual meeting of stockholders which was
held on May 15, 2002 in Houston, Texas:
(i) Election of Directors:
Abstained
For Against or Withheld
---------- ------- -----------
James C. Flores............................................ 18,602,420 -- 1,385,168
Jerry L. Dees.............................................. 19,901,217 -- 86,371
Tom H. Delimitros.......................................... 19,901,217 -- 86,371
William H. Hitchcock....................................... 19,901,217 -- 86,371
John H. Lollar............................................. 19,901,217 -- 86,371
D. Martin Phillips......................................... 19,901,217 -- 86,371
Robert V. Sinnott.......................................... 19,901,217 -- 86,371
J. Taft Symonds............................................ 19,901,217 -- 86,371
(ii) Ratification of PricewaterhouseCoopers LLC, independent
certified public accountants, as auditors of the Company's
financial statements for the fiscal year ended December 31,
2002....................................................... 19,583,926 403,060 602
Of the 23,700,296 shares of common stock issued and outstanding on March 22,
2002, 19,987,588 were voted.
All matters received the required number of votes for approval.
35
Item 6--Exhibits and Reports on Form 8-K
A. Exhibits
4.1 Indenture dated as of July 3, 2002, among Plains Exploration & Production Company, L.P.
(the "Company"), Plains E&P Company (the "Co-Issurer", together with the Company, the
"Issuers"), the Subsidiary Guarantors and JPMorgan Chase Bank, as Trustee, for 8 3/4%
Senior Subordinated Notes due 2012.
4.2 Registration Rights agreement dated July 3, 2002, by and among the Issuers, the Guarantors
(as defined therein) and the Initial Purchasers (as defined therein).
4.3 Warrant effective November 12, 1997 to Highbridge International LLC for the purchase of
150,000 shares of common stock Plains Resources Inc.
10.1 Credit Agreement dated as of July 3, 2002 among Plains Exploration & Production Company,
L.P,, as Borrower, JPMorgan Chase Bank, as administrative agent, Bank One, NA and Fleet
national bank, as Syndication Agents, BNP Paribas and Fortis Capital Corp., as
Documentation Agents, and the Lenders party hereto.
10.2 First Amendment, effective as of July 19, 2002, to Credit Agreement dated as of July 3, 2002
among Plains Exploration & Production Company, L.P,, as Borrower, JPMorgan Chase Bank,
as administrative agent, Bank One, NA and Fleet national bank, as Syndication Agents, BNP
Paribas and Fortis Capital Corp., as Documentation Agents, and the Lenders party hereto.
10.3 Employee Matters Agreement entered into as of July 3, 2002, between Plains Resources Inc.
and Plains Exploration and Production Company, L.P.
10.4 Tax Allocation Agreement entered into as of July 3, 2002, between Plains Resources Inc. and
Plains Exploration and Production Company, L.P.
10.5 Master Separation Agreement entered into as of July 3, 2002, between Plains Resources Inc.
and Plains Exploration and Production Company, L.P.
10.6 Plains Exploration and Production Company, L.P. Transition Services Agreement entered into
as of July 3, 2002, between Plains Resources Inc. and Plains Exploration and Production
Company, L.P.
10.7 Technical Services Agreement entered into as of July 3, 2002, between Plains Resources
Inc., Calumet Florida, L.L.C. and Plains Exploration and Production Company, L.P.
10.8 Intellectual Property Agreement entered into as of July 3, 2002, between Plains Resources
Inc. and Plains Exploration and Production Company, L.P.
10.9 Plains Resources Inc. Transition Services Agreement entered into as of July 3, 2002, between
Plains Resources Inc. and Plains Exploration and Production Company, L.P.
99.1 Chief Executive Officer Certification Pursuant to 18 U.S.C Section 1350, as Adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002
99.2 Chief Financial Officer Certification Pursuant to 18 U.S.C Section 1350, as Adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002
B. Reports on Form 8-K
A Current Report on Form 8-K was filed on August 8, 2002 with respect to
current estimates of certain results for the third quarter and fourth
quarter of 2002.
A Current Report on Form 8-K was filed on July 10, 2002, which filed as
an exhibit a press release issued on July 3, 2002 to announce PXP's issuance
of its 8.75% notes, PXP's entering into its new credit facility, our
repayment of outstanding balances under our old credit facility, and our
election to redeem our outstanding 10.25% notes.
A Current Report on Form 8-K was filed on June 24, 2002, which filed as
an exhibit our press release issued on June 21, 2002 to announce our receipt
of a favorable private letter ruling from the IRS related to the spin-off,
PXP's filing of a registration statement with the SEC for an IPO of PXP's
common stock, our intention to refinance our outstanding debt, and our
anticipated management realignment.
Items 3 & 5 are not applicable and have been omitted
36
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 12, 2002
/s/ CYNTHIA A. FEEBACK
By: _________________________________
Cynthia A. Feeback
Senior Vice President--Accounting
and
Treasurer (Principal Accounting
Officer)
37