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 September 30, 2004
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OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
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Commission file number 1-8483
UNOCAL CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 95-3825062
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2141 ROSECRANS AVENUE, SUITE 4000, EL SEGUNDO, CALIFORNIA 90245
(Address of principal executive offices) (Zip Code)
(310) 726-7600 (Registrant's telephone number,
including area code)
Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
------- -------
Indicate by check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Exchange Act). Yes X No
------- -------
Number of shares of Common Stock, $1.00 par value, outstanding as of
October 29, 2004: 263,181,376
UNOCAL CORPORATION
TABLE OF CONTENTS
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PAGE
GLOSSARY.................................................................... i
FORWARD-LOOKING STATEMENTS.................................................. iii
PART I FINANCIAL INFORMATION
Item 1. Financial Statements.
Consolidated Earnings............................................. 1
Consolidated Balance Sheets....................................... 2
Consolidated Cash Flows........................................... 3
Notes to Consolidated Financial Statements........................ 4
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations....................... 34
Item 3. Quantative and Qualitative Disclosures About Market Risk............ 51
Item 4. Controls and Procedures............................................. 55
PART II OTHER INFORMATION
Item 1. Legal Proceedings................................................... 56
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds......... 57
Item 6. Exhibits............................................................ 57
SIGNATURE 58
EXHIBIT INDEX 58
GLOSSARY
Below are definitions of certain key terms that may be used in this Form 10-Q:
M Thousand Bbl Barrels
MM Million Cf/d Cubic feet per day
B Billion Cfe/d Cubic feet of gas
T Trillion equivalent per day
Btu British thermal units
CF Cubic feet DD&A Depreciation, depletion
and amortization
BOE Barrels of oil equivalent NGLs Natural gas liquids
Liquids Crude oil, condensate
and NGLs
Bbl/d Barrels per day
o API Gravity is a measurement of the gravity (density) of crude oil and
other liquid hydrocarbons by a system recommended by the American Petroleum
Institute ("API"). The measuring scale is calibrated in terms of "API
degrees." The higher the API gravity, the lighter the oil.
o Bilateral institution refers to a country specific institution that lends
funds primarily to promote the export of goods from that country. Examples
of bilateral institutions are Ex-Im (U.S.), Hermes (Germany), SACE (Italy),
COFACE (France), and JBIC (Japan).
o BOE is a term used to quantify oil and natural gas amounts using a standard
measurement. Gas volumes are converted to barrels of oil equivalent on the
basis of energy content, where the volume of natural gas that when burned
produces the same amount of heat as a barrel of oil (6,000 cubic feet of
gas equals one barrel of oil equivalent).
o British Thermal Units ("Btu") is a standardized unit of measure for energy,
equivalent to the amount of heat required to raise the temperature of one
pound of water one degree Fahrenheit. Ten thousand MMBtu (million Btu) is
the standard volume for exchange traded natural gas derivative contracts,
the approximate heat content of ten thousand Mcf (thousand cubic feet) of
natural gas.
o Delineation or appraisal well is a well drilled in an unproven area
adjacent to a discovery well to define the boundaries of the reservoir.
o Development well is a well drilled within the proved area of an oil or
natural gas reservoir to a depth of a stratigraphic horizon known to be
productive.
o Dry hole is a well incapable of producing hydrocarbons in sufficient
commercial quantities to justify future capital expenditures for completion
and additional infrastructure.
o Economic interest method pursuant to production sharing contracts is a
method by which our share of the cost recovery revenue and the profit
revenue is divided by market oil and gas prices and represents the volume
to which we are entitled. The lower the commodity price, the higher the
volume entitlement, and vice versa.
o Exploratory well is a well drilled to find and produce oil or natural gas
reserves that is not a development well.
o Farm-in or farm-out is an agreement whereby the owner of a working interest
in an oil and gas lease assigns the working interest or a portion thereof
to another party who agrees to pay a portion of past or future costs. The
interest received by an assignee is a "farm-in," while the interest
transferred by the assignor is a "farm-out."
o Field is an area consisting of a single reservoir or multiple reservoirs
all grouped on or related to the same individual geological structural
feature or stratigraphic condition.
o Floating Production Storage and Offloading ("FPSO") technology refers to
the use of a vessel that is stationed above or near an offshore oil field.
Produced fluids from platform based and subsea completion wells are brought
by flowlines to the vessel where they are separated, treated, stored and
then offloaded to another vessel for transportation.
i
o Gross acres or gross wells are the total acres or wells in which we have a
working interest.
o Hydrocarbons are organic compounds of hydrogen and carbon atoms that form
the basis of all petroleum products.
o Lifting is the amount of liquids each working-interest partner takes
physically. The liftings may be more or less than actual entitlements based
on royalties, working interest percentages, and a number of other factors.
o Liquefied Natural Gas ("LNG") is a gas, mainly methane, which has been
liquefied in a refrigeration and pressurization process to facilitate
storage and transportation.
o Liquefied Petroleum Gas ("LPG") is a mixture of butane, propane and other
light hydrocarbons. At normal temperature it is a gas, but when cooled or
subjected to pressure it can be stored and transported as a liquid.
o Multilateral institution refers to an institution with shareholders from
multiple countries that lends money for specific development reasons.
Examples of multilateral institutions are International Finance Corporation
("IFC"), European Bank for Reconstruction and Development ("EBRD"), and
Asian Development Bank ("ADB").
o Natural Gas Liquids ("NGLs") are primarily ethane, propane, butane and
natural gasolines which can be extracted from wet natural gas and become
liquid under various combinations of increasing pressure and lower
temperature.
o Net acreage and net oil and gas wells are obtained by multiplying gross
acreage and gross oil and gas wells by our working interest percentage in
the properties.
o Net pay is the amount of oil or gas saturated rock capable of producing oil
or gas.
o Net working interest is a working interest after deducting royalties.
o OPEC is the abbreviation for Organization of Petroleum Exporting Countries.
o Producible well is a well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of
production exceed production expenses and taxes.
o Production Sharing Contract ("PSC") is a contractual agreement between us
and a host government whereby we, act as contractor, bear all exploration,
development and production costs in return for an agreed upon share of the
proceeds from the sale of production.
o Prospective acreage is lease acreage on which wells have not been drilled
or completed to a point that would permit the production of commercial
quantities of oil and natural gas.
o Proved acreage is acreage that is allocated to producing wells or wells
capable of production or to acreage that is being developed.
o Reservoir is a porous and permeable underground formation containing oil
and/or natural gas enclosed or surrounded by layers of less permeable rock
and is individual and separate from other reservoirs.
o Subsea tieback is a well with the wellhead equipment located on the bottom
of the ocean.
o Take-or-Pay is a type of contract clause where specific quantities of a
product must be paid for, even if delivery is not taken. Normally, the
purchaser has the right in following years to take product that had been
paid for but not taken.
o Trend or Play is an area or region of concentrated activity with a group of
related fields and/or prospects.
o Working interest is the percentage of ownership we have in a joint venture,
partnership, consortium, project or acreage.
o West Texas Intermediate ("WTI") crude oil is a light, sweet crude oil (high
API gravity, low sulfur) used as the benchmark for U.S. crude oil refining
and trading. WTI is deliverable at Cushing, Oklahoma to fill New York
Mercantile Exchange ("NYMEX") futures contracts for light, sweet crude oil.
-------------------------------------
For the purpose of this report, the terms "Unocal," "Union Oil," "we,"
"our," "its" and the "Company" refer to Unocal Corporation ("Unocal") and its
consolidated subsidiaries, including Union Oil Company of California ("Union
Oil"), unless the context otherwise provides.
ii
FORWARD-LOOKING STATEMENTS
This report contains forward-looking statements. All statements other
than historical facts are forward-looking. These statements may be identified by
words such as "expects," "anticipates," "intends," "plans," "believes,"
"estimates," "forecasts," "could," "will" and words of similar meaning, and
include statements regarding:
o exploratory drilling, project development and other plans and objectives for
future operations,
o oil and gas production rates, timing and growth,
o operating and capital expenditures,
o negotiations, sales and transactions with third parties,
o the availability of cash on hand, borrowings and cash from asset sales and
financings to fund our activities,
o possible contingent payments pursuant to completed transactions,
o future tax refunds,
o commodity prices,
o the amount and timing of contingent liabilities for environmental, litigation
and tax matters, under guarantees and indemnities and under our benefit and
medical plans,
o economic conditions,
o the impact of new or existing accounting pronouncements, and
o repurchases of our common stock from time to time.
Although these statements are based upon our current expectations and
beliefs, they are subject to known and unknown risks and uncertainties that
could cause actual results and outcomes to differ materially from those
described in, or implied by, the forward-looking statements. In that event, our
business, financial condition, results of operations or liquidity could be
materially adversely affected and investors in our securities could lose part or
all of their investments. These risks and uncertainties include:
o volatility in commodity prices,
o our ability to find or acquire commercially productive oil and gas reservoirs
and to develop and produce deepwater fields and other complex projects in a
timely and cost-effective manner,
o local demand, infrastructure and the distance to markets for our hydrocarbon
production,
o the accuracy of our estimates and judgments regarding hydrocarbon resources
and formations,
o decline rates of producing properties,
o adverse geological and other operational factors, such as formation
irregularities, equipment failures or shortages, fires, blow-outs and weather
conditions,
o our success in competing against other energy companies and retaining and
attracting qualified personnel,
o future costs for environmental, litigation and other contingent liabilities
and those under our benefit and medical plans,
o the extent of our operating cash flow and other capital resources available
to fund capital expenditures,
o regulatory factors, such as changes in environmental laws and receipt of
required permits and licenses,
o international and domestic political and economic factors,
o other risks associated with our substantial international operations, such as
trade barriers, currency fluctuations and restrictions on repatriation of
earnings,
o our ability to enter into agreements and transactions on acceptable terms
with, and performance by, foreign governmental entities, joint venture
partners, independent contractors, equipment suppliers, operators of
properties in which we have an interest and other third parties,
o market conditions for our common stock, and
o other factors discussed in our 2003 Annual Report on Form 10-K, as amended,
and subsequent reports filed by us with the U.S. Securities and Exchange
Commission ("SEC").
Copies of our SEC filings are available by calling us at (800) 252-2233
or from the SEC by calling (800) SEC-0330. The reports are also available on our
web site, www.unocal.com. We undertake no obligation to update the
forward-looking statements in this report to reflect future events or
circumstances. All such statements are expressly qualified by this cautionary
statement.
iii
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CONSOLIDATED EARNINGS (UNAUDITED) UNOCAL CORPORATION
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
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Millions of dollars except per share amounts 2004 2003 2004 2003
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Revenues
Sales and operating revenues $ 1,961 $ 1,472 $ 5,712 $ 4,797
Interest, dividends and miscellaneous income 6 (2) 36 18
Gain on sales of assets 26 65 110 115
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Total revenues 1,993 1,535 5,858 4,930
Costs and other deductions
Crude oil, natural gas and product purchases 772 447 2,288 1,629
Operating expense 316 344 978 962
Administrative and general expense 35 61 144 199
Depreciation, depletion and amortization 248 231 720 744
Impairments 28 83 42 86
Dry hole costs 12 14 77 95
Exploration expense 51 39 149 182
Interest expense 40 45 127 119
Property and other operating taxes 19 18 61 61
Distributions on convertible preferred securities of subsidiary trust - 8 - 24
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Total costs and other deductions 1,521 1,290 4,586 4,101
Earnings from equity investments 31 54 106 150
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Earnings from continuing operations before
income taxes and minority interests 503 299 1,378 979
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Income taxes 172 145 495 442
Minority interests 2 4 6 8
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Earnings from continuing operations 329 150 877 529
Earnings from discontinued operations (a) 1 2 63 17
Cumulative effect of accounting changes (b) - - - (83)
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Net earnings $ 330 $ 152 $ 940 $ 463
==============================================================================================================================
Basic earnings per share of common stock (c)
Continuing operations $ 1.25 $ 0.58 $ 3.34 $ 2.05
Discontinued operations 0.01 0.01 0.24 0.06
Cumulative effect of accounting changes - - - (0.32)
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Net earnings $ 1.26 $ 0.59 $ 3.58 $ 1.79
==============================================================================================================================
Diluted earnings per share of common stock (d)
Continuing operations $ 1.22 $ 0.57 $ 3.25 $ 2.02
Discontinued operations 0.01 0.01 0.23 0.06
Cumulative effect of accounting changes - - - (0.30)
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Net earnings $ 1.23 $ 0.58 $ 3.48 $ 1.78
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Cash dividends declared per share of common stock $ 0.20 $ 0.20 $ 0.60 $ 0.60
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(a) Net of tax (benefit) $ - $ 2 $ 32 $ 11
(b) Net of tax (benefit) $ - $ - $ - $ (48)
(c) Basic weighted average shares outstanding (in thousands) 262,628 258,525 262,839 258,244
(d) Diluted weighted average shares outstanding (in thousands) 274,287 272,691 276,292 272,172
See Notes to the Consolidated Financial Statements.
-1-
CONSOLIDATED BALANCE SHEETS UNOCAL CORPORATION
At September 30, At December 31,
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Millions of dollars 2004 (a) 2003
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Assets
Current assets
Cash and cash equivalents $ 780 $ 404
Accounts and notes receivable - net 1,369 1,292
Inventories 198 141
Deferred income taxes 99 119
Other current assets 33 35
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Total current assets 2,479 1,991
Investments and long-term receivables - net 827 892
Properties - net (b) 8,639 8,324
Goodwill 133 131
Deferred income taxes 272 300
Other assets 170 160
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Total assets $ 12,520 $ 11,798
===================================================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ 1,126 $ 1,072
Taxes payable 355 326
Dividends payable 53 52
Interest payable 49 43
Current portion of environmental liabilities 106 118
Current portion of long-term debt and capital leases 235 248
Other current liabilities 239 226
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Total current liabilities 2,163 2,085
Long-term debt and capital leases 2,842 2,635
Deferred income taxes 737 704
Accrued abandonment, restoration and environmental liabilities 891 844
Other deferred credits and liabilities 1,016 960
Minority interests 37 39
Commitments and contingencies - Note 17
Company-obligated mandatorily redeemable convertible preferred
securities of a subsidiary trust holding solely parent debentures - 522
Common stock ($1 par value, shares authorized: 750,000,000 (c)) 278 271
Capital in excess of par value 1,229 1,031
Unearned portion of restricted stock issued (25) (13)
Retained earnings 4,237 3,456
Accumulated other comprehensive income (301) (298)
Notes receivable - key employees (3) (27)
Treasury stock - at cost (d) (581) (411)
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Total stockholders' equity 4,834 4,009
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Total liabilities and stockholders' equity $ 12,520 $ 11,798
===================================================================================================================
(a) Unaudited
(b) Net of accumulated depreciation, depletion and amortization of: $ 12,387 $ 11,711
(c) Number of shares outstanding (in thousands) 262,527 260,594
(d) Number of shares (in thousands) 15,292 10,623
See Notes to the Consolidated Financial Statements.
-2-
CONSOLIDATED CASH FLOWS (UNAUDITED) UNOCAL CORPORATION
For the Nine Months
Ended September 30,
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Millions of dollars 2004 2003
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Cash Flows from Operating Activities
Net earnings $ 940 $ 463
Adjustments to reconcile net earnings to
net cash provided by operating activities
Depreciation, depletion and amortization 720 746
Impairments 42 86
Dry hole costs 77 95
Amortization of exploratory leasehold costs 47 88
Deferred income taxes 13 102
Gain on sales of assets (110) (115)
Gain on disposal of discontinued operations (86) (13)
Pension expense net of contributions (35) 65
Restructuring provisions net of payments (18) 22
Cumulative effect of accounting changes - 83
Other (24) 5
Working capital and other changes related to operations
Accounts and notes receivable 41 (15)
Inventories (57) (35)
Accounts payable 54 20
Taxes payable 29 55
Other 59 1
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Net cash provided by operating activities 1,692 1,653
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Cash Flows from Investing Activities
Capital expenditures (includes dry hole costs) (1,243) (1,296)
Proceeds from sales of assets 278 343
Proceeds from sales of discontinued operations 123 11
Return of capital from affiliate company 48 -
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Net cash used in investing activities (794) (942)
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Cash Flows from Financing Activities
Long-term borrowings 137 154
Reduction of long-term debt and capital lease obligations (247) (156)
Minority interests (2) (257)
Repurchases of common stock (170) -
Repurchases of preferred securities (253) -
Proceeds from issuance of common stock 149 15
Dividends paid on common stock (158) (155)
Loans to key employees 24 0
Other (2) 5
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Net cash used in financing activities (522) (394)
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Net increase in cash and cash equivalents 376 317
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Cash and cash equivalents at beginning of year 404 168
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Cash and cash equivalents at end of period $ 780 $ 485
=====================================================================================================================
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized) $ 122 $ 123
Income taxes (net of refunds) $ 402 $ 310
See Notes to the Consolidated Financial Statements.
-3-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
1. General
The consolidated financial statements included in this report are unaudited and,
in the opinion of our management, include all adjustments necessary for a fair
presentation of financial position and results of operations. All adjustments
are of a normal recurring nature.
Certain notes and other information have been condensed or omitted from these
interim financial statements in accordance with the Securities and Exchange
Commission ("SEC") disclosure requirements for Form 10-Q. Therefore, these
interim consolidated financial statements should be read in conjunction with the
consolidated financial statements and the related notes filed with the SEC in
our 2003 Annual Report on Form 10-K, as amended.
Our consolidated financial statements include the accounts of subsidiaries in
which a controlling interest is held and variable interest entities where Unocal
is the primary beneficiary. Investments in entities without a controlling
interest are generally accounted for by the equity method. Under the equity
method, our investments are stated at cost plus the equity in undistributed
earnings and losses after acquisition. Income taxes estimated to be payable when
earnings are distributed are included in deferred income taxes. Other securities
and investments excluding marketable securities are generally carried at cost.
Undivided interests in oil and gas joint ventures are consolidated on a
proportionate basis. We follow the successful efforts method of accounting for
our oil and gas activities.
Results for the nine months ended September 30, 2004, are not necessarily
indicative of future financial results.
We made changes in the reporting of our segments from the reporting utilized in
the 2003 Annual Report on Form 10-K, as amended (see note 22 - Segment Data).
The financial statements of the prior periods have been reclassified to conform
to the 2004 presentation.
2. Accounting Changes
SFAS No. 132 (revised 2003): In 2003, we adopted Statement of Financial
Accounting Standards ("SFAS") No. 132, "Employers' Disclosures about Pensions
and Other Postretirement Benefits (revised 2003)." In accordance with this
pronouncement, beginning in 2004, quarterly reports include disclosure of the
components of net pension and postretirement benefit cost as well as the changes
in the estimated current year contributions to the plans. In addition, benefit
payment information will be included in our 2004 Annual Report on Form 10-K.
FASB Interpretation No. 46 (revised December 2003): Effective January 1, 2004,
we adopted Financial Accounting Standards Board ("FASB") Interpretation No. 46
(revised December 2003), "Consolidation of Variable Interest Entities" which
clarifies the definition of a variable interest entity and provides a scope
exception for certain entities that meet the Statement's definition of a
"business." This pronouncement resulted in the deconsolidation of Unocal Capital
Trust (the "Trust") (see note 15 for further details). As a result, the $522
million obligation for the Trust's convertible preferred securities was removed
from the consolidated balance sheet and replaced by an increase in long-term
debt for the $538 million in 6-1/4% convertible junior subordinated debentures
of Unocal payable to the Trust. We also recorded a $16 million investment in the
Trust on the consolidated balance sheet. The deconsolidation did not affect our
consolidated net earnings. In the third quarter of 2004, we redeemed $269
million of the debentures and reduced our investment in the Trust by $8 million
(see note 15 - Variable Interest Entities).
FASB Staff Position No. 142-2: In September 2004, the FASB issued Staff Position
No. 142-2, "Application of FASB Statement No. 142, Goodwill and Other Intangible
Assets, to Oil- and Gas-Producing Entities," that clarifies that oil and gas
drilling rights are tangible assets. This position is consistent with our
classification of the cost of acquiring oil and gas drilling rights in property,
plant and equipment on our consolidated balance sheet. Therefore, adoption of
this rule had no impact on either our earnings or consolidated balance sheet.
-4-
FASB Staff Position No. 106-2: In December 2003, "The Medicare Prescription
Drug, Improvement and Modernization Act of 2003" (the "Act") was enacted, which
introduces a prescription drug benefit under Medicare Part D. The availability
of the new drug benefit could cause Medicare eligible plan participants to leave
their current employer-sponsored plans (or cause employees to join such plans),
depending on the drug benefits provided under those plans relative to the
benefits provided by Medicare. The Act also provides that a non-taxable federal
subsidy will be paid to sponsors of postretirement benefit plans that provide
retirees with a drug benefit that is at least "actuarially equivalent" to the
Medicare Part D benefit. The federal subsidy is not payable to a plan sponsor
for retirees who leave their current employer-sponsored plan to participate in
the Medicare drug program. As of January 1, 2004, the Act's subsidy reduced the
Accumulated Postretirement Benefit Obligation ("APBO") of our U.S.
Postretirement Welfare plan by $72 million, which will be amortized to future
earnings as an actuarial experience gain. In accordance with FASB Staff Position
No.106-2, in the third quarter of 2004, we recorded a benefit of $8 million
representing 75 percent of the estimated full year impact of the subsidy. This
amount consisted of $3 million for the reduction in interest cost, $4 million
for amortization of the actuarial gain and $1 million for the reduction in
service cost. These amounts are subject to future revision because final
detailed regulations specifying the manner in which actuarial equivalency must
be determined and the evidence required to demonstrate it are not yet available.
EITF Issue 03-1: "The Meaning of Other-Than-Temporary Impairment and Its
Application to Certain Investments," is effective with the 2004 Form 10-K and
requires additional disclosures for cost method investments. This consensus
reached by the FASB's Emerging Issues Task Force ("EITF") also provides
recognition and measurement guidance regarding impairment of cost method
investments. Adoption of this pronouncement is not expected to have an impact on
either our earnings or consolidated balance sheet.
EITF Issue 03-16: "Accounting for Investments in Limited Liability Companies
("LLCs")," is effective beginning with the third quarter 2004. This
pronouncement may cause some entities to be accounted for by the equity method
rather than on a cost basis. Adoption of this pronouncement did not have an
impact on either our earnings or consolidated balance sheet in the third quarter
of 2004.
EITF Issue 04-9: SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas
Producing Companies" requires the cost of drilling an exploratory well to be
capitalized pending determination of whether the well has found proved reserves.
If this determination cannot be made at the conclusion of drilling, SFAS No. 19
sets out additional requirements for continuing to carry the cost of the well as
an asset. These requirements include firm plans for further drilling and a
one-year time limitation on continued capitalization in certain instances. The
EITF in their discussions of this issue noted that as a result of the increasing
complexity of oil and gas projects due to drilling in remote and deepwater
offshore locations, companies increasingly require more than one year to
complete all of the activities that permit recognition of proved reserves.
Furthermore, because of new technologies, additional exploratory wells may no
longer be required before a major project can commence. EITF Issue 04-9
"Accounting for Suspended Well Costs," seeks to determine whether SFAS No. 19
should be clarified to recognize the industry changes that have taken place in
the past quarter century. This issue was discussed at the EITF's September 2004
meeting and it was determined that a formal amendment to SFAS No. 19 would be
required if the FASB concurs with broadening the requirements for continued
capitalization of exploratory well costs.
American Jobs Creation Act: The American Jobs Creation Act of 2004 (the "Act")
was signed into law by the U.S. President on October 22, 2004. The Act
contains numerous changes to U.S. tax law, both temporary and permanent in
nature, including a potential tax deduction with respect to certain qualified
domestic manufacturing activities, changes in the carryback and carryforward
utilization periods for foreign tax credits and a dividend received deduction
with respect to accumulated income earned abroad. The new law could potentially
have an impact on our effective tax rate, future taxable income and cash and tax
planning strategies, amongst other affects. We are currently in the process of
evaluating the impact that the Act will have on our financial position and
results of operations.
3. Other Financial Information
o Revenues - During the third quarters of 2004 and 2003, approximately 25
percent and 20 percent, respectively, of total sales and operating revenues
were attributable to the resale of liquids and natural gas purchased from
others in connection with marketing activities. For the nine months ended
September 30, 2004 and 2003, these percentages were approximately 26
percent and 23 percent, respectively. Related purchase costs are classified
as expense in the crude oil, natural gas and product purchases category on
the consolidated earnings statement.
-5-
o Capitalized Interest - During the third quarters of 2004 and 2003,
capitalized interest totaled $18 million and $11 million, respectively. For
the nine months ended September 30, 2004 and 2003, capitalized interest
totaled $44 million and $46 million, respectively. The slight decrease in
the nine month period of 2004 as compared to the same period a year ago was
primarily due to lower capitalized interest from the West Seno development
project in Indonesia that was mostly offset by higher capitalized interest
from the Azerbaijan International Operating Company ("AIOC") project in
Azerbaijan and the Mad Dog project in the Gulf of Mexico.
o Exploration Expense - Our exploration expense on the consolidated earnings
statement consisted of the following:
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
--------------------- --------------------
Millions of dollars 2004 2003 2004 2003
--------------------------------------------------------------------------------
Exploration operations $ 19 $ 13 $ 55 $ 44
Geological and geophysical 15 7 39 41
Amortization of exploratory
leasehold costs 14 17 47 88
Leasehold rentals 3 2 8 9
--------------------------------------------------------------------------------
Exploration expense $ 51 $ 39 $ 149 $ 182
================================================================================
Amortization of exploratory leasehold costs for the nine month period of
2004 was lower than the comparable period of 2003, which included a $26
million pre-tax provision resulting from our decision to relinquish 44
deepwater Gulf of Mexico blocks before the end of their lease term. The
remaining decrease in the amortization of exploratory leasehold costs for
the nine month period of 2004 is principally due to lower amortization
levels for the Gulf of Mexico compared to a year ago.
4. Dispositions Of Assets
Certain asset sales are discussed below:
In the third quarter of 2004, we sold our 50 percent equity interest in a
jointly held project company that owned UnoPaso Exploracao e Producao de
Petroleo e Gas Ltda., a Brazilian exploration and production venture, for $67
million in cash plus possible future payments that are contingent on attainment
of certain natural gas prices and/or volume thresholds. The underlying assets
sold represented net production of approximately 4.5 MBOE/d and were our
remaining oil and natural gas assets in Brazil. We recorded an after-tax gain of
$1 million.
In the third quarter of 2004, we sold non-oil and gas property in Parachute,
Colorado for $26 million in cash. We recorded an after-tax gain of $16 million
in the quarter.
Our subsidiary, Pure Resources Inc. ("Pure"), sold certain of its mineral fee
lands it held in several states to Black Stone Minerals Company, LP. The sale
involved Pure's royalty interests, overriding royalty interests and minor
working interests. The $190 million sale price included approximately $75
million for the prospective portion of these mineral fee lands resulting in a
$22 million after-tax gain that was recorded in the second quarter of 2004. The
net proceeds received were $176 million after sale price adjustments to reflect
the effective date of the transaction as October 1, 2003. The sale of the
producing portion of these lands was recorded in discontinued operations (see
note 8 for further detail).
Our subsidiary, Unocal North Sumatra Geothermal, Ltd. ("UNSG"), received about
$60 million from PT PLN (Persero) ("PLN"), the state electricity utility, for
the sale of our rights and interests in the Sarulla geothermal project on the
island of Sumatra, Indonesia. PLN acquired UNSG's interest in the Joint
Operation Contract with Pertamina, the Indonesian national petroleum company and
the Energy Sales Contract with PLN. We recorded a $21 million after-tax gain
from the sale in the first quarter of 2004.
-6-
5. Impairment of Assets
As part of our assessment, we review our developed and undeveloped oil and gas
properties and other long-lived assets for possible impairment. In the nine
month period of 2004, we recorded pre-tax impairment charges of $42 million.
Approximately $20 million was attributable to oil and gas fields in the U.S.,
the majority of which related to impairments of warehouse stock for the Gulf of
Mexico region, which was mostly recorded in the third quarter of 2004.
In addition, we recorded an impairment of approximately $11 million relating to
our equity investment in a gas-fired power-plant project in the third quarter of
2004 and impairments of $5 million relating to our equity investment in an LPG
terminal in East China. In the nine month period of 2003, we recorded pre-tax
impairment charges of $86 million, most of which was recorded in the third
quarter of 2003. Pre-tax impairments of approximately $79 million were related
to oil and gas fields in the Gulf of Mexico region. In addition, we recorded
an impairment of approximately $5 million pre-tax in 2003 relating to our
investment in the Trans-Andean oil pipeline, which transports crude oil from
Argentina to Chile.
6. Restructuring
In 2003, we accrued $38 million pre-tax in restructuring charges and adopted a
plan for streamlining our organizational structures in order to align them with
our portfolio requirements and business needs. These charges represented the
costs associated with eliminating 360 positions and were included in
administrative and general expense on the consolidated earnings statement in the
second, third and fourth quarters of 2003. During the second quarter of 2004,
the plan was modified to reflect a reduction of 36 employees involved in the
restructuring and the subsequent reversal of $2 million pre-tax in previously
recognized costs. At September 30, 2004, 307 of 324 employees in the plan had
been terminated. The remaining 17 individuals have been advised of planned
termination dates as a result of the plan. The following table reflects the 2004
plan activity. The majority of the remaining liability of $8 million is expected
to be paid by the end of 2004.
Training /
Number of Termination Out-placement
Millions of dollars (except employees) Employees Costs Costs
--------------------------------------------------------------------------------
Liability at December 31, 2003 360 $ 24 $ 2
1st Quarter Payments 7 -
--------------------------------------------------------------------------------
Liability at March 31, 2004 $ 17 $ 2
2nd Quarter adjustments (36) (2) -
2nd Quarter payments 4 1
--------------------------------------------------------------------------------
Liability at June 30, 2004 324 $ 11 $ 1
3rd Quarter payments 4 -
--------------------------------------------------------------------------------
Liability at September 30, 2004 324 $ 7 $ 1
================================================================================
7. Income Taxes
Income taxes on earnings from continuing operations for the third quarter and
nine month periods of 2004 were $172 million and $495 million, respectively,
compared with $145 million and $442 million for the comparable periods of 2003.
The effective income tax rates for the third quarter and nine month periods of
2004 were 34 percent and 36 percent, respectively, compared with 48 percent and
45 percent, for each of the third quarter and nine month periods of 2003,
respectively. The overall lower effective tax rates for both the third quarter
and nine month periods of 2004, as compared to the same periods a year ago, are
due primarily to net tax benefits of $32 million recorded in the third quarter
of 2004 and $60 million for the nine month period of 2004 relating primarily to
settlements and assessments with various taxing authorities (see note 17 - "Tax
Matters" for additional detail) and the tax benefit effect in 2004 of currency
related adjustments in Thailand.
-7-
8. Discontinued Operations
In June 2004, our Pure subsidiary sold certain of its prospective and producing
mineral fee lands in the U.S., which included approximately 2 MBOE/d of
production in Mississippi, Arkansas and Alabama (see note 4 for further
details). The $190 million sale price included approximately $115 million for
the producing portion of these mineral fee lands resulting in an after-tax gain
of approximately $44 million. The gain on the producing asset disposal plus
normal results of operations prior to the sale have been reported as
discontinued operations in the consolidated earnings statement. These properties
generated revenues of $12 million and net earnings of approximately $6 million
in 2004 up to the sale date in June 2004. For the nine month period of 2003,
these properties generated revenues of $18 million and net earnings of
approximately $8 million.
We also sold our Cal Ven Pipeline system located in Alberta, Canada, for
approximately $19 million in May 2004 and recorded an after-tax gain of
approximately $13 million. The gain plus normal results of operations prior to
the sale have been reported as discontinued operations in the consolidated
earnings statement. The Cal Ven pipeline generated revenues of $1 million and
net earnings of approximately $0.4 million in 2004 up to the sale date and
revenues of $3 million and net earnings of approximately $1 million in the nine
month period of 2003.
In 2003, we recorded an after-tax gain of $8 million related to the 1997 sale of
our former West Coast refining, marketing and transportation assets. The sales
agreement contained a provision calling for payments to us for price differences
between California Air Resources Board Phase 2 gasoline and conventional
gasoline. This provision of the agreement terminated at the end of 2003.
The following table summarizes the results from these discontinued operations:
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
-------------------------------------------------
Millions of dollars 2004 2003 2004 2003
--------------------------------------------------------------------------------
Revenues $ - $ 7 $ 13 $ 21
Total costs and other deductions - 3 3 6
--------------------------------------------------------------------------------
Earnings from discontinued
operations before income taxes - 4 10 15
Income taxes on
discontinued operations - 2 4 6
--------------------------------------------------------------------------------
Earnings from discontinued
operations - 2 6 9
Gain on disposal of discontinued
operations before income taxes 2 - 86 13
Income taxes on disposal of
discontinued operations 1 - 29 5
--------------------------------------------------------------------------------
Gain on disposal of
discontinued operations 1 - 57 8
--------------------------------------------------------------------------------
Total earnings from
discontinued operations $ 1 $ 2 $ 63 $ 17
================================================================================
-8-
9. Earnings Per Share
The following are reconciliations of the numerators and denominators of the
basic and diluted earnings per share ("EPS") computations for earnings from
continuing operations for the third quarter and nine month periods ended
September 30, 2004 and 2003:
--------------------------------------------------------------------------------
Earnings Shares Per Share
Millions except per share amounts (Numerator) (Denominator) Amount
--------------------------------------------------------------------------------
Three months ended September 30, 2004
Earnings from continuing operations $ 329 262.6
Basic EPS $ 1.25
======
Effect of dilutive securities
Options and common stock equivalents 1.5
--------------------
329 264.1 $ 1.25
Interest on convertible
debentures payable to trust (after-tax) 6 10.2
--------------------
Diluted EPS $ 335 274.3 $ 1.22
======
Three months ended September 30, 2003
Earnings from continuing operations $ 150 258.5
Basic EPS $ 0.58
======
Effect of dilutive securities
Options and common stock equivalents 1.9
--------------------
150 260.4 $ 0.58
Distributions on subsidiary trust
preferred securities (after-tax) 7 12.3
--------------------
Diluted EPS $ 157 272.7 $ 0.57
======
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
Earnings Shares Per Share
Millions except per share amounts (Numerator) (Denominator) Amount
--------------------------------------------------------------------------------
Nine months ended September 30, 2004
Earnings from continuing operations $ 877 262.8
Basic EPS $ 3.34
======
Effect of dilutive securities
Options and common stock equivalents 1.9
--------------------
877 264.7 $ 3.31
Interest on convertible
debentures payable to trust (after-tax) 20 11.6
--------------------
Diluted EPS $ 897 276.3 $ 3.25
======
Nine months ended September 30, 2003
Earnings from continuing operations $ 529 258.2
Basic EPS $ 2.05
======
Effect of dilutive securities
Options and common stock equivalents 1.7
--------------------
529 259.9 $ 2.04
Distributions on subsidiary trust
preferred securities (after-tax) 21 12.3
--------------------
Diluted EPS $ 550 272.2 $ 2.02
======
--------------------------------------------------------------------------------
Certain options were not included in the computation of diluted EPS as the
exercise prices were greater than average market prices of the common shares
during the respective periods. For the three month and nine month periods ended
September 30, 2004, there were options outstanding to purchase approximately 1.1
million and 1.2 million shares, respectively, of common stock that were excluded
from the computation of diluted EPS. In the three month and nine month periods
ended September 30, 2003, there were options outstanding to purchase
approximately 8.8 million and 9 million shares, respectively, of common stock
that were excluded from the computation of diluted EPS.
-9-
10. Stock-Based Compensation
Prior to 2003, we applied Accounting Principles Board ("APB") Opinion No. 25,
"Accounting for Stock Issued to Employees," and related interpretations in
accounting for stock-based compensation. Accordingly, stock-based compensation
expense recognized in our consolidated earnings included expenses related to
various cash incentive plans that were paid to certain employees based upon
defined measures of Unocal's common stock price performance and total
shareholder return. In addition, the amounts also included expenses related to
our Pure subsidiary, which had its own stock-based compensation plans. Under APB
Opinion No. 25, stock-based employee compensation cost was not recognized in
earnings when stock options granted had an exercise price equal to the market
value of the underlying common stock on the date of grant.
Effective January 1, 2003, we adopted the fair value recognition provisions of
SFAS No. 123, "Accounting for Stock-Based Compensation," prospectively to all
employee awards granted, modified, or settled after December 31, 2002.
Therefore, the cost related to stock-based employee compensation included in the
determination of net earnings for 2004 is less than that which would have been
recognized if the fair value based method had been applied to all awards since
the original effective date of SFAS No. 123. The following table illustrates the
effect on net earnings and earnings per share if the fair value based method had
been applied to all outstanding and unvested awards in each period:
For the Three For the Nine
Months Ended Months Ended
September 30, September 30,
----------------------------------
Millions of dollars except per share amounts 2004 2003 2004 2003
--------------------------------------------------------------------------------
Net earnings
As reported $ 330 $ 152 $ 940 $ 463
Add: Stock-based employee compensation
expense included in reported net
income, net of related tax effects
and minority interests 2 4 9 10
Deduct: Total stock-based employee
compensation expense determined
under the fair value based method
for all awards, net of related tax
effects and minority interest (2) (5) (11) (15)
----------------------------------
Pro forma net earnings $ 330 $ 151 $ 938 $ 458
==================================
Net earnings per share:
Basic - as reported $1.26 $0.59 $3.58 $1.79
Basic - pro forma $1.26 $0.58 $3.57 $1.78
Diluted - as reported $1.23 $0.58 $3.48 $1.78
Diluted - pro forma $1.23 $0.58 $3.47 $1.76
-10-
11. Comprehensive Income
Unocal's comprehensive income is detailed in the following table:
For the Three For the Nine
Months Ended Months Ended
September 30, September 30,
----------------------------------
Millions of dollars 2004 2003 2004 2003
--------------------------------------------------------------------------------
Net earnings $ 330 $ 152 $ 940 $ 463
Change in unrealized holding
gain on investments (a) - 8 - 8
Change in unrealized gain (loss)
on hedging instruments (b) (2) 17 (18) 14
Reclassification adjustment for
settled hedging contracts (c) (15) 5 (12) 16
Unrealized foreign currency
translation adjustments 56 2 27 116
Minimum pension liability adjustment (d) - (21) - (21)
--------------------------------------------------------------------------------
Total comprehensive income $ 369 $ 163 $ 937 $ 596
================================================================================
(a) Net of tax effect of: - 5 - 5
(b) Net of tax effect of: (1) 10 (11) 8
(c) Net of tax effect of: (9) 3 (7) 9
(d) Net of tax effect of: - 12 - 12
12. Assets Held for Sale
In the second quarter of 2004, we sold certain of our prospective mineral fee
lands in North America (see note 8 - Discontinued Operations). These lands were
held for sale as of December 31, 2003.
In the first quarter of 2004, our UNSG subsidiary sold its rights and interests
in the Sarulla geothermal project on the island of Sumatra, Indonesia (see note
4 - Disposition Of Assets). This property was held for sale as of December 31,
2003.
13. Postemployment Benefit Plans
We have numerous plans worldwide that provide employees with retirement
benefits. We also have medical plans that provide health care benefits for
eligible employees and many of our retired employees. Most of our plans covering
employees outside of North America are unfunded and resulting liabilities are
extinguished on a "pay as you go" basis.
The components of net periodic benefit cost for our pension and postretirement
medical plans for the three month and nine month periods ending September 30,
2004 and September 30, 2003 were:
For the Three Months
Ended Septemeber 30,
Pension Benefits Other Benefits
---------------- --------------
Millions of dollars 2004 2003 2004 2003
--------------------------------------------------------------------------------
Service cost (net of employee contributions) $ 10 $ 8 $ 1 $ 1
Interest cost 21 21 3 7
Expected return on plan assets (23) (22) - -
Amortization of:
Prior service cost 1 2 - -
Net actuarial (gains) losses 16 17 (1) 3
Curtailment and settlement (gains) losses - - - -
--------------------------------------------------------------------------------
Net periodic pension and
other benefit cost (credit) $ 25 $ 26 $ 3 $ 11
================================================================================
For the Nine Months
Ended Septemeber 30,
Pension Benefits Other Benefits
---------------- --------------
Millions of dollars 2004 2003 2004 2003
--------------------------------------------------------------------------------
Service cost (net of employee contributions) $ 26 $ 21 $ 3 $ 3
Interest cost 61 57 16 18
Expected return on plan assets (61) (59) - -
Amortization of:
Prior service cost 4 5 - -
Net actuarial (gains) losses 46 47 6 8
Curtailment and settlement (gains) losses - 3 - 1
--------------------------------------------------------------------------------
Net periodic pension and
other benefit cost (credit) $ 76 $ 74 $ 25 $ 30
================================================================================
-11-
The assumed weighted-average rates used to determine the preceding net periodic
benefit costs were:
Pension Benefits Other Benefits
----------------------------------------------------
Weighted-average assumptions 2004 2003 2004 2003
--------------------------------------------------------------------------------
Discount rates 6.00% 6.74% 6.00% 6.75%
Rates of salary increases 4.91% 4.93% 4.99% 4.99%
Expected returns on plan assets 8.00% 8.40% N/A N/A
In December 2003, "The Medicare Prescription Drug, Improvement and Modernization
Act of 2003" was enacted. As of January 1, 2004, the Act's non-taxable federal
subsidy reduced the Accumulated Postretirement Benefit Obligation ("APBO") of
our U.S. Postretirement Welfare plan by $72 million, which will be amortized to
future earnings as an actuarial gain. In keeping with the guidance provided by
FASB Staff Position 106-2, we recorded a benefit of $8 million in the third
quarter of 2004, representing 75 percent of the estimated full year impact of
the subsidy. This amount consisted of $3 million for the reduction in interest
cost, $4 million for amortization of the actuarial experience gain and $1
million for the reduction in service cost.
We are not required under existing funding or tax regulations to make any cash
contributions to our U.S. Qualified Retirement Plan in 2004; however, we did
make a voluntary $100 million pre-tax contribution to our U.S. Qualified
Retirement Plan on July 29, 2004.
We disclosed in our financial statements for the year ended December 31, 2003
that we expected to contribute approximately $48 million in support of our
various postemployment benefit plans. This amount consists of $4 million to our
Supplemental Executive Retirement plans, approximately $17 million to our
foreign pension plans and approximately $27 million to our worldwide
postretirement medical plans in 2004. As of September 30, 2004, we anticipate
that actual contributions in support of our worldwide post employment benefit
plans (exclusive of the aforementioned $100 million contribution to our U.S.
Qualified Retirement Plan) in 2004 will not vary materially from the levels
forecasted at year-end 2003.
14. Long Term Debt
Unocal's total consolidated debt, including current maturities, was $3.08
billion at September 30, 2004, compared with $2.88 billion at the end of 2003.
The increase primarily reflects the recognition of $538 million in 6-1/4%
convertible junior subordinated debentures, payable to the Trust, as long term
debt, replacing the $522 million convertible preferred securities of the Trust.
In the third quarter of 2004, we paid the Trust to redeem half of its
convertible preferred securities, which reduced our outstanding balance on the
6-1/4% convertible junior subordinated debentures to $269 million (see note 2
and note 15 for further detail).
During the nine month period of 2004, we also retired $173 million in 6.375%
notes and paid down $20 million of medium-term notes, which matured during the
period. In addition, we retired the remaining $24 million limited recourse loan
balance under the Azerbaijan International Operating Company's Early Oil Project
in 2004. We also made a $15 million principal payment on the variable rate
portion of the Overseas Private Investment Corporation ("OPIC") Financing
Agreement for the West Seno project in Indonesia, which is scheduled to mature
in June 2009.
These decreases were partially offset by $40 million in new borrowings related
to Phase 1 development of the Azeri-Chirag-Gunashli structure in the Azerbaijan
sector of the Caspian Sea, scheduled for repayment semiannually from June 2006
through December 2015 and $95 million drawn under two new loans from the OPIC
Financing Agreement, both limited recourse loans, for the first phase of the
West Seno project in Indonesia. One loan was drawn for $50 million and the other
was drawn for $45 million, and they each carry fixed rates of 3.61% and 4.78%,
respectively. Principal payments on the $50 million loan are scheduled
semiannually from June 2005 to December 2007, and on the $45 million loan
payments are scheduled from June 2005 to June 2008.
A capital lease of $30 million was also added during the second quarter of 2004
for a 10-year lease agreement on a floating storage unit for our Thailand
production operations. The lease agreement has an extension option for an
additional 5 years.
-12-
15. Variable Interest Entities
In 1996, Unocal exchanged 10,437,873 newly issued 6-1/4% trust convertible
preferred securities of Unocal Capital Trust, a Delaware statutory trust, for
shares of a then-outstanding issue of convertible preferred stock. Unocal
acquired the convertible preferred securities, which had an aggregate
liquidation value of $522 million, from the Trust, together with 322,821 common
securities of the Trust, which had an aggregate liquidation value of $16
million, in exchange for $538 million principal amount of 6-1/4% convertible
junior subordinated debentures of Unocal. The Trust was accounted for as a
100-percent-owned consolidated finance subsidiary of Unocal, with the debentures
and payments thereon by Unocal to the Trust eliminated in the consolidated
financial statements. The trust convertible preferred securities have been fully
and unconditionally guaranteed by Unocal in accordance with the terms of
Unocal's guarantee agreement.
Pursuant to FASB Interpretation No. 46 "Consolidation of Variable Interest
Entities" as revised in December 2003 (see note 2 for further details), we
deconsolidated the Trust in the first quarter of 2004. As a result, the $522
million obligation for the convertible preferred securities was removed from the
consolidated balance sheet and replaced by $538 million in 6-1/4% convertible
junior subordinated debentures of Unocal payable to the Trust. In addition, we
recorded our $16 million investment in the Trust in investments and long-term
receivables-net on the consolidated balance sheet. Effective in the first
quarter of 2004, interest payments on the debentures are now recorded as
interest expense on the consolidated earnings statement. In prior periods,
payments to the holders of the preferred securities were reported as a separate
line item on the consolidated earnings statement. Payments are subject to
deferral under certain circumstances. If payments are deferred, Unocal would be
prohibited from paying dividends on its common stock during the deferral period.
In the third quarter of 2004, the Trust called 5,218,452, or approximately half,
of its outstanding convertible preferred securities. Holders converted 304,150
preferred securities into Unocal common stock and the remaining 4,914,302
convertible preferred securities were redeemed for $246 million, plus a $3
million premium. In connection with this redemption program, Unocal redeemed
$269 million of its convertible junior subordinated debentures held by the Trust
using cash on hand and by issuing $15 million in Unocal common stock. The Trust
utilized the cash it received from Unocal to redeem the 4,914,302 preferred
securities and to retire 152,016 of the Trust's common securities which
Unocal held as an investment. The Trust now holds $269 million of Unocal's
convertible junior subordinated debentures and Unocal holds 170,805 common
securities of the Trust, approximating an $8 million investment.
16. Accrued Abandonment, Restoration and Environmental Liabilities
At September 30, 2004, we had accrued $745 million in estimated abandonment and
restoration costs as liabilities. At December 31, 2003, we had accrued $710
million in estimated abandonment and restoration costs. The increase in the
liability account from December 31, 2003 was due to $33 million in accrued
pre-tax accretion expense, $10 million in revisions to existing estimates and
$12 million in new abandonment liabilities recorded during the period.
Abandonment liability settlements totaled $20 million during the nine month
period of 2004.
Our reserve for environmental remediation obligations at September 30, 2004
totaled $252 million, of which $106 million was included in current liabilities.
This compared with $252 million at December 31, 2003, of which $118 million was
included in current liabilities.
17. Commitments and Contingencies
Unocal has contingent liabilities for existing or potential claims, lawsuits and
other proceedings, including those involving environmental, tax, guarantees and
other matters, some of which are discussed more specifically below. We accrue
liabilities when it is probable that future costs will be incurred and these
costs can be reasonably estimated. Accruals are based on developments to date,
our estimates of the outcomes of these matters and our experience in contesting,
litigating and settling other matters. As the scope of the liabilities becomes
better defined, there will be changes in the estimates of future costs, which
could have a material effect on our future results of operations, financial
condition or liquidity.
-13-
Environmental matters
We continue to move forward to address environmental issues for which we are
responsible. In cooperation with regulatory agencies and others, we follow
procedures that we have established to identify and cleanup contamination
associated with past operations. We are subject to loss contingencies pursuant
to federal, state, local and foreign environmental laws and regulations. These
include existing and possible future obligations to investigate the effects of
the release or disposal of certain petroleum, chemical and mineral substances at
various sites; to remediate or restore these sites; to compensate others for
damage to property and natural resources, for remediation and restoration costs
and for personal injuries; and to pay civil penalties and, in some cases,
criminal penalties and punitive damages. These obligations relate to sites owned
by us or owned by others and are associated with past and present operations,
including sites at which we have been identified as a potentially responsible
party ("PRP") under the federal Superfund laws and comparable state laws.
Liabilities are accrued when it is probable that future costs will be incurred
and such costs can be reasonably estimated. However, in many cases,
investigations are not yet at a stage where we are able to determine whether we
are liable or, even if liability is determined to be probable, to quantify the
liability or estimate a range of possible exposure. In such cases, the amounts
of our liabilities are indeterminate due to the potentially large number of
claimants for any given site or exposure, the unknown magnitude of possible
contamination, the imprecise and conflicting engineering evaluations and
estimates of proper clean-up methods and costs, the unknown timing and extent of
the corrective actions that may be required, the uncertainty attendant to the
possible award of punitive damages, the recent judicial recognition of new
causes of action, the present state of the law, which often imposes joint and
several and retroactive liabilities on PRPs, the fact that we are usually just
one of a number of companies identified as a PRP, or other reasons.
Assessment and Remediation
As disclosed in note 16, at September 30, 2004, we had accrued $252 million for
estimated future environmental assessment and remediation costs at various sites
where liabilities for such costs are probable and reasonably estimable. The
amount accrued represents our reserve for assessment and remediation obligations
based on currently available facts, existing technology and presently enacted
laws and regulations. The remediation cost estimates, in many cases, are based
on plans recommended to the regulatory agencies for approval and are subject to
future revisions. The ultimate costs to be incurred could exceed the total
amounts reserved. We may also incur additional liabilities in the
future at sites where remediation liabilities are probable but future
environmental costs are not presently reasonably estimable because the sites
have not been assessed or the assessments have not advanced to the stage where
costs are reasonably estimable. At those sites where investigations or
feasibility studies have advanced to the stage of analyzing feasible alternative
remedies and/or ranges of costs, we estimate that we could incur possible
additional remediation costs aggregating approximately $225 million. The amount
of such possible additional costs reflects the aggregate of the high ends of the
ranges of costs of feasible alternatives that we identified for those sites with
respect to which investigation or feasibility studies have advanced to the stage
of analyzing such alternatives. However, such estimated possible additional
costs are not an estimate of the total remediation costs beyond the amounts
reserved, because there are sites where we are not yet in a position to estimate
all, or in some cases any, possible additional costs. Both the amounts reserved
and estimates of possible additional costs will be adjusted as additional
information becomes available regarding the nature and extent of site
contamination, required or agreed-upon remediation methods and other actions by
government agencies and private parties. Therefore, the amounts reserved and the
possible additional estimated costs may change in the near term, and in some
cases could change substantially.
During the nine month period ended September 30, 2004, cash payments of $63
million were applied against the reserves and $63 million was added to the
reserves. Possible additional remediation costs increased by $20 million during
the nine month period of 2004. The accrued costs and the estimated possible
additional costs are shown below for four categories of sites:
-14-
At September 30, 2004
---------------------------------
Estimated Possible
Millions of dollars Reserve Additional Costs
-------------------------------------------------------------------------------
Superfund and similar sites $ 15 $ 15
Active Company facilities 31 35
Company facilities sold with retained liabilities
and former Company-operated sites 97 80
Inactive or closed Company facilities 109 95
-------------------------------------------------------------------------------
Total $ 252 $ 225
===============================================================================
The time frames over which the amounts included in the reserve may be paid
extend from the near term to several years into the future. The sites included
in the above categories are in various stages of investigation and remediation;
therefore, the related payments against the existing reserve will be made in
future periods. Also, some of the work is dependent upon reaching agreements
with regulatory agencies and/or other third parties on the scope of remediation
work to be performed, who will perform the work, the timing of the work, who
will pay for the work and other factors that may have an impact on the timing of
the payments for amounts included in the reserve. For some sites, the
remediation work will be performed by other parties, such as the current owners
of the sites, and we have a contractual agreement to pay a share of the
remediation costs. For these sites, we generally have less control over the
timing of the work and consequently the timing of the associated payments. Based
on available information, we estimate that the majority of the amounts included
in the reserve will be paid within the next three to five years.
At the sites where we have contractual agreements to share remediation costs
with third parties, the reserve reflects our estimated shares of those costs. In
many of the oil and gas sites, remediation cost sharing is included in joint
venture agreements that were made with third parties during the original
operation of the sites. In many cases where we sold facilities or a business to
a third party, sharing of remediation costs for those sites may be included in
the sales agreement.
Superfund and Similar Sites
---------------------------
Contamination at the sites of the "Superfund and similar sites" category
was the result of the disposal of substances at these sites by one or more
PRPs. Contamination of these sites could be from many sources, of which we
may be one. We have been notified that we are a PRP at the sites included
in this category. At the sites where we have not denied liability, our
contribution to the contamination at these sites was primarily from
operations in the categories. Included in this category of sites are:
o the McColl site in Fullerton, California
o the Operating Industries site in Monterey Park, California
o the Casmalia Waste site in Casmalia, California
At September 30, 2004, we have received notifications from the U.S.
Environmental Protection Agency ("EPA") that we may be a PRP at 23 sites
and may share certain liabilities at these sites. Of the total, four sites
are under investigation and/or litigation, and our potential liability is
not presently determinable; and for two sites, our potential liability
appears to be de minimis. Of the remaining 17 sites, where we have
concluded that liability is probable and to the extent costs can be
reasonably estimated, a reserve of $11 million has been established for
future remediation and settlement costs.
Various state agencies and private parties had identified 22 other similar
PRP sites. Five sites are under investigation and/or litigation, and our
potential liability is not presently determinable; and at three sites, our
potential liability appears to be de minimis. Where we have concluded that
liability is probable and to the extent costs can be reasonably estimated
at the remaining 14 sites, a reserve of $4 million has been established for
future remediation and settlement costs.
The sites discussed above exclude 128 sites where our liability has been
settled, or where we have no evidence of liability and there has been no
further indication of liability by government agencies or third parties for
at least a 12-month period.
-15-
We do not consider the number of sites for which we have been named a PRP
as a relevant measure of liability. Although the liability of a PRP is
generally joint and several, we are usually just one of numerous companies
designated as a PRP. Our ultimate share of the remediation costs at those
sites often is not determinable due to many unknown factors. The solvency
of other responsible parties and disputes regarding responsibilities may
also impact our ultimate costs.
Active Company facilities
-------------------------
The "Active Company facilities" category includes oil and gas fields and
mining operations. The oil and gas sites are primarily contaminated with
crude oil, oil field waste and other petroleum hydrocarbons. Contamination
at the active mining sites was principally the result of the impact of
mined material on the groundwater and/or surface water at these sites.
Included in this category are:
o the Molycorp molybdenum mine in Questa, New Mexico
o the Molycorp lanthanide facility in Mountain Pass, California
o Alaska oil and gas properties.
We have a reserve of $31 million for estimated future costs of remedial
orders, corrective actions and other investigation, remediation and
monitoring obligations at certain operating facilities and producing oil
and gas fields. We recorded provisions of $9 million during the nine month
period of 2004. The provisions were primarily for the estimated additional
costs of the remedial investigation and feasibility study (RI/FS) that is
continuing at a molybdenum mine located in Questa, New Mexico, which is
owned by our Molycorp, Inc. ("Molycorp") subsidiary. The estimated
additional costs are based on an evaluation that Molycorp performed in the
second quarter of 2004 of the remaining work that will be required to
complete the RI/FS. Molycorp has been conducting the RI/FS cooperatively
with the U.S. Environmental Protection Agency to determine what, if any,
adverse impacts past mining operations may have had on the environment.
During the nine month period of 2004, we made payments of $6 million for
this category of sites.
Company facilities sold with retained liabilities and former Company
operated sites
--------------
The "Company facilities sold with retained liabilities and former
Company-operated sites" category includes our former refineries,
transportation and distribution facilities and service stations. The
required remediation of these sites is mainly for petroleum hydrocarbon
contamination as the result of leaking tanks, pipelines or other equipment
or impoundments that were used in these operations. Also included in this
category are former oil and gas fields that we no longer operate. In most
cases, these sites are contaminated with crude oil, oil field waste and
other petroleum hydrocarbons. Contamination at other sites in these
categories of sites was the result of former industrial
chemical and polymers manufacturing and distribution facilities and
agricultural chemical retail businesses. Included in this category are:
o West Coast refining, marketing and transportation sites
o auto/truckstop facilities in various locations in the U.S.
o industrial chemical and polymer sites in the South, Midwest and
California
o agricultural chemical sites in the West and Midwest.
In each sale, we retained a contractual remediation or indemnification
obligation and are responsible only for certain environmental problems that
resulted from operations prior to the sale. The reserve represents
estimated future costs for remediation work: identified prior to the sale
of these sites; included in negotiated agreements with the buyers of these
sites where we retained certain levels of remediation liabilities; and/or
identified in subsequent claims made by buyers of the properties. Our
former operated sites include service stations, distribution facilities and
oil and gas fields that we previously operated but did not own.
-16-
We have an aggregate reserve of $97 million for this group of sites. During
the nine month period of 2004, provisions of $42 million for this category
were recorded. These provisions were primarily for approximately 225 sites
where we had operated service stations, bulk plants or terminals. The
provisions were based on new and revised cost estimates that were developed
for these sites in the nine month period of 2004. The provisions were also
for new and revised cost estimates for the assessment and remediation of
oil fields in Michigan and California. We will perform assessments on areas
within these fields to determine if they have been contaminated by our
former operations. We have determined that other areas within these sites
are contaminated and will require cleanup. Payments of $44 million were
made during the nine month period of 2004 for sites in this category.
Inactive or closed Company facilities
-------------------------------------
The "Inactive or closed Company facilities" category includes former oil
and gas fields and other locations that are no longer operating. In most
cases, these sites are contaminated with crude oil, oil field waste and
other petroleum hydrocarbons. Other sites in this category were
contaminated from former ferromolybdenum production operations. Included in
this category are:
o the Guadalupe oil field on the central California coast
o the Molycorp Washington facility in Pennsylvania
o the Beaumont Refinery in Texas.
A reserve of $109 million has been established for these types of
facilities. During the nine month period of 2004, we accrued $11 million
related to sites in this category primarily for the Beaumont Refinery site
and for a former terminal site in Edmonds, Washington. A provision was
recorded for the updated cost estimates to close impoundments used in our
former operations at the Beaumont, Texas site. In the first quarter of
2004, final design work and related detailed cost estimates to close these
impoundments were completed. We also received final approval of a permit
for these projects from the Texas Commission on Environmental Quality. The
reserve for this category of sites was also increased for the estimated
cost of cleanup work at a shutdown terminal in Edmonds, Washington. The
cost includes the implementation and operation of a system to remediate
petroleum hydrocarbon contamination caused by our former petroleum products
storage and transportation operation at the facility. Payments of $12
million were made during the nine month period of 2004 for sites in this
category.
Legal Compliance
We are subject to federal, state and local environmental laws and regulations,
including the Comprehensive Environmental Response, Compensation and Liability
Act of 1980 ("CERCLA"), as amended, the Resource Conservation and Recovery Act
("RCRA") and laws governing low level radioactive materials. Under these laws,
we are subject to existing and/or possible obligations to remove or mitigate the
environmental effects of the disposal or release of certain chemical, petroleum
and radioactive substances at various sites. Corrective investigations and
actions pursuant to RCRA and other federal, state and local environmental laws
are being performed at our facility in Beaumont, Texas, a former agricultural
chemical facility in Corcoran, California, Molycorp's facility in Washington,
Pennsylvania and other facilities. In addition, Molycorp is required to
decommission its Washington facility in Pennsylvania pursuant to the terms of
its radioactive source materials license and decommissioning plan.
We also must provide financial assurance for future closure and post-closure
costs of our RCRA-permitted facilities and for decommissioning costs at
Molycorp's Washington Pennsylvania facility under its radioactive source
materials license. Pursuant to a 1998 settlement agreement between us and the
State of California (and the subsequent stipulated judgment entered by the
Superior Court), we must provide financial assurance for anticipated costs of
remediation activities at our inactive Guadalupe oil field. As previously
discussed, remediation reserves for these sites are included in the "Inactive or
closed Company facilities" category and totaled $92 million at September 30,
2004. At those sites where investigations or feasibility studies have advanced
to the stage of analyzing alternative remedies and/or ranges of costs, we
estimate that we could incur possible additional remediation costs aggregating
approximately $63 million. Although any possible additional costs for these
sites are likely to be incurred at different times and over a period of many
years, we believe that these obligations could have a material adverse effect on
our results of operations but are not expected to be material to our
consolidated financial condition or liquidity.
-17-
Insurance
We maintain insurance coverage intended to reimburse the cost of damages and
remediation related to environmental contamination resulting from sudden and
accidental incidents under current operations. The purchased coverages contain
specified and varying levels of deductibles and payment limits. Although certain
of our contingent legal exposures enumerated above are uninsurable either due to
insurance policy limitations, public policy or market conditions, our management
believes that our current insurance program significantly reduces the
possibility of an incident causing us a material adverse financial impact.
Certain Litigation and Claims
Agrium Litigation: In June 2002, a lawsuit was filed against us by Agrium Inc.,
a Canadian corporation, and Agrium U.S. Inc., its U. S. subsidiary, in the
Superior Court of the State of California for the County of Los Angeles (Agrium
U.S. Inc. and Agrium Inc. v. Union Oil Company of California, Case No. BC275407)
(the "Agrium Claim"). Simultaneously, we filed suit against the Agrium entities
("Agrium") in the U.S. District Court for the Central District of California
(Union Oil Company of California v. Agrium, Inc., Case No. 02-04518 NM) (the
"Company Claim"). We subsequently removed the Agrium Claim to the U.S. District
Court for the Central District of California (Case No. 02-04769 NM). The federal
court remanded the Agrium Claim to the California Superior Court. In addition,
we initiated arbitration concerning the Gas Purchase and Sale Agreement ("GPSA")
between us and Agrium U.S. Inc. (AAA Case No. 70 198 00539 02) (the
"Arbitration").
The Agrium Claim alleges numerous causes of action relating to Agrium's purchase
from us of a nitrogen-based fertilizer plant on the Kenai Peninsula, Alaska, in
September 2000. The primary allegations involve our obligation to supply natural
gas to the plant pursuant to the GPSA. Agrium alleges that we misrepresented the
amount of natural gas reserves available for sale to the plant as of the closing
of the transaction and that we have failed to develop additional natural gas
reserves for sale to the plant. Agrium also alleges that we misrepresented the
condition of the general effluent sewer at the plant and made misrepresentations
regarding other environmental matters.
Agrium seeks damages in an unspecified amount for breach of such representations
and warranties, as well as for alleged misconduct by us in operating and
managing certain oil and gas leases and other facilities. Agrium also seeks
declaratory relief for the calculation of payments under a "Retained Earnout"
covenant in the Purchase and Sale Agreement for the plant (the "PSA") that
entitles us to certain contingent payments based on the price of ammonia
subsequent to the September 2000 closing. The complaint includes demands for
punitive damages and attorneys' fees.
In September 2002, Agrium amended its complaint to add allegations that we
breached certain conditions of the September 2000 closing, breached certain
indemnification obligations, and violated the pertinent health and safety code.
Agrium also asked for recission of the sale of the fertilizer plant, in
addition, or as an alternative, to money damages. In addition, Agrium sought a
declaration by the arbitration panel that has been convened (see below) that
natural gas from Unocal's Ninilchik, Happy Valley fields in South Kenai "or
elsewhere" should be delivered to the plant to meet Unocal's alleged obligations
under the GPSA.
In the Company Claim, we seek declaratory relief in our favor against the
allegations of Agrium set forth above and for judgment on the Retained Earnout
in the amount of $17 million plus interest accrued subsequent to May 2002.
Unocal also sought reimbursement of over $5 million in royalties paid to the
State of Alaska.
The GPSA contains a contractual limit on liquidated damages of $25 million per
year, not to exceed a total of $50 million over the life of the agreement. In
addition, the PSA contains a limit on damages of $50 million.
On July 16, 2003, the court approved an agreed stipulation between the parties
to submit all issues under the GPSA to arbitration. The arbitration proceedings
commenced May 24, 2004. The arbitration panel issued its ruling on July 22,
2004. The arbitration panel agreed with us that the GPSA is a reserves-based
contract. The panel's decision laid out the methodology for determining past and
future gas delivery quantities and for calculating liquidated damages arising
from underdeliveries of gas by us to the fertilizer plant. Using the
methodology, the arbitration panel found we owed Agrium $36 million through
April 2004 plus $2 million in interest through the arbitration ruling date for
underdelivery of natural gas to the fertilizer plant. Based on current delivery
projections from certain dedicated fields, we expect to reach the GPSA $50
million cap for liquidated damages by the end of 2004 for underdeliveries
subsequent to April 2004.
-18-
The arbitration panel did not rule on the enforceability of this $50 million cap
because its award did not exceed the amount of the cap. The parties continue to
disagree over the cap's enforceability. The arbitration panel also ordered
Agrium to reimburse us $5 million for excess royalties that have been paid by us
to the state of Alaska. We paid Agrium $36 million plus $2 million in interest
in September 2004.
The litigation related to the PSA remains pending in California Superior Court
in Los Angeles County. We believe we have a meritorious defense to each of the
Agrium remaining claims, but that in any event our exposure to damages for all
disputes under the agreements is limited by those agreements. Agrium alleges
that it is entitled to recover damages in excess of those amounts. Trial has
been set for May 18, 2005.
Petrobangla Claim: In July 2002, our subsidiary Unocal Bangladesh Blocks
Thirteen and Fourteen, Ltd. ("Unocal Blocks 13 and 14 Ltd.") received a letter
from the Bangladesh Oil, Gas & Mineral Corporation ("Petrobangla") claiming, on
behalf of the Bangladesh government and Petrobangla, compensation allegedly due
in the amount of $685 million for 246 BCF of recoverable natural gas allegedly
"lost and damaged" in a 1997 blowout and ensuing fire during the drilling by
Occidental Petroleum Corporation (known at that time in Bangladesh as Occidental
of Bangladesh Ltd.) ("OBL"), as operator, of the Moulavi Bazar #1 ("MB #1")
exploration well on the Blocks 13 and 14 PSC area in Northeast Bangladesh.
Unocal and OBL believe that the claim vastly overstates the amount of
recoverable gas involved in the blowout.
Consistent with worldwide industry contracting practice, there was no provision
in the PSC for compensating the Bangladesh government or Petrobangla for
resources lost during the contractor's operations. Even if some form of
compensation were due, Unocal and OBL believe that settlement compensation for
the blowout was fully addressed in a 1998 Supplemental Agreement to the PSC (the
"Supplemental Agreement"), which, among other matters, waived OBL's then
50-percent contractor's share (as well as the then 50-percent contractor's share
held by our Unocal Bangladesh, Ltd., subsidiary ("Unocal Bangladesh")) of
entitlement to the recovery of costs incurred in the drilling of the MB #1 and
the blowout, waived their right to invoke force majeure in connection with the
blowout, and reduced by five percentage points their contractors' profit share
(with a concomitant increase in Petrobangla's profit share) of future production
from the sands encountered by the MB #1 well to a drill depth of 840 meters or,
if the blowout sand reservoir were not present or development is not feasible
deemed commercial, from other commercial fields in the Moulavi Bazar
"ring-fenced" area of Block 14. Consequently, Unocal and OBL consider the matter
closed and Unocal Blocks 13 and 14 Ltd. has advised Petrobangla that no
additional compensation is warranted. By Writ Petition Affidavit dated March 24,
2003, a concerned citizen filed suit in the Bangladesh lower court (Alam v.
Bangladesh, Petrobangla, Department of Environment, and Unocal Bangladesh, Ltd.,
Supreme Court of Bangladesh, High Court Division, Writ Petition No. 2461 of
2003) on the basis of the MB #1 blowout. We were notified of the suit on May 26,
2003 when we received the court's order to show cause why the Supplemental
Agreement should not be declared illegal and cancelled on account of its having
been executed without lawful authority, and why Unocal Bangladesh should not be
directed to stop exploration until it compensates for the MB# 1 blowout. No
hearing is currently scheduled on the matter, and we believe the action is not
well founded.
Tax Matters
We believe we have adequately provided in our accounts for tax items and issues
not yet resolved. Several prior material tax issues are unresolved. Resolution
of these tax issues affects not only the year in which the items arose, but also
our tax situation in other tax years.
With respect to the 1979-1994 taxable years, the Joint Committee on Taxation of
the U.S. Congress has reviewed and approved the settlement of all issues for
these years, including the carryback of a 1993 net operating loss to taxable
year 1984 and resultant credit adjustments, as previously agreed with the
Appeals division of the Internal Revenue Service ("IRS"). This settlement and
corresponding recalculation of taxable income and credits for this period
resulted in an overpayment of taxes. We have received a cash refund of $33
million in October 2004 and expect to receive approximately another $30 million
by the end of the year, representing overpaid taxes plus interest thereon. An
additional refund is anticipated in the first quarter of 2005. Taxable years
1979-1984 are now closed and barred from additional assessment of federal income
taxes. Although the IRS has completed its audit of Unocal for taxable years
1985-1994 and a settlement has been reached for all such years, these years
cannot be formally closed until a separate audit by the IRS of the Alaska
Kuparuk River Unit tax partnership is completed. Accordingly, the IRS refers to
the 1985-1994 taxable years as "partially closed." All such developments have
been considered in our accounts.
-19-
With respect to the 1995-1997 taxable years, a settlement of all issues has been
reached with the Appeals division of the IRS. Although the IRS has completed its
audit of Unocal for taxable years 1995-1997 and a settlement has been reached
for all such years, these years cannot be formally closed until a separate audit
by the IRS of the Alaska Kuparuk River Unit tax partnership is completed.
Accordingly, the IRS refers to the 1995-1997 taxable years as "partially
closed." All such developments have been considered in our accounts.
The 1998-2001 taxable years are before the Exam division of the IRS.
With respect to state tax matters, a tentative settlement has been reached with
the Franchise Tax Board of the state of California with respect to taxable years
1989-1991. We have received cash refunds of $20 million in October 2004 and
anticipate receiving at least another $27 million by the end of the year,
representing overpaid taxes plus interest thereon.
Guarantees Related to Assets or Obligations of Third Parties
Future Remediation Costs
We have agreed to indemnify certain third parties for particular future
remediation costs that may be incurred for properties held by these parties. The
guarantees were established when we either leased property from or sold property
to these third parties. The properties may or may not have been contaminated by
our former operations. Where it has been or will be determined that we are
responsible for contamination, the guarantees require us to pay the costs to
remediate the sites to specified cleanup levels or to levels that will be
determined in the future.
The maximum potential amount of future payments that we could be required to
make under these guarantees is indeterminate primarily due to the following: the
indefinite term of the majority of these guarantees; the unknown extent of
possible contamination; uncertainties related to the timing of the remediation
work; possible changes in laws governing the remediation process; the unknown
number of claims that may be made; changes in remediation technology; and the
fact that most of these guarantees lack limitations on the maximum potential
amount of future payments.
We have accrued probable and reasonably estimable assessment and remediation
costs for the locations covered under these guarantees. These amounts are
included in the "Company facilities sold with retained liabilities and former
Company-operated sites" category of our reserve for environmental remediation
obligations.
At September 30, 2004, the reserve for this category totaled $97 million. For
those sites where investigations or feasibility studies have advanced to the
stage of analyzing feasible alternative remedies and/or ranges of costs, we
estimate that we could incur possible additional remediation costs aggregating
approximately $80 million.
BTC Construction Completion Guarantee
We have a construction completion guarantee related to debt financing
arrangements for the Baku-Tbilisi-Ceyhan ("BTC") pipeline project. We have an
equity interest in the development of this pipeline from Baku, Azerbaijan
through Georgia to the Mediterranean port of Ceyhan, Turkey. Our maximum
potential future payments under the guarantee are estimated to be $310 million.
The debt is secured by transportation proceeds from production of the Azeri
field in the Caspian Sea. The debt is non-recourse upon financial completion
certification, which is expected by 2009. As of September 30, 2004, we have
recorded a liability of $19 million as the estimated value of this guarantee.
Other Guarantees and Indemnities
We have also guaranteed the debt of certain other entities accounted for by the
equity method. The majority of this debt matures ratably through the year 2014.
The maximum potential amount of future payments we could be required to make is
approximately $15 million.
-20-
In the ordinary course of business, we have agreed to indemnify cash
deficiencies for certain domestic pipeline joint ventures, which we account for
on the equity method. These guarantees are considered in our analysis of overall
risk. Because most of these agreements do not contain spending caps, it is not
possible to quantify the amount of maximum payments that may be required.
Nevertheless, we believe the payments would not have a material adverse impact
on our financial condition or liquidity.
Financial Assurance for Unocal Obligations
Surety Bonds and Letters of Credit
In the normal course of business, we have performance obligations that are
secured, in whole or in part, by surety bonds or letters of credit. These
obligations primarily cover self-insurance, site restoration, dismantlement and
other programs where governmental organizations require such support. These
surety bonds and letters of credit are issued by financial institutions and are
required to be reimbursed by us if drawn upon. At September 30, 2004, we had
obtained various surety bonds for $180 million. These surety bonds included a
bond for $69 million securing our performance under a fixed price natural gas
sales contract for the delivery of 72 billion cubic feet of gas over a ten-year
period that began in January of 1999 and will end in December of 2008 and $111
million in various other routine performance bonds held by local, city, state
and federal agencies. We also had obtained $87 million in standby letters of
credit at September 30, 2004, of which $29 million represented letters of credit
with the revenue department in Thailand relating to a tax appeal, $20 million
represented a letter of credit for margin requirements for gas purchases in
Canada and $14 million represented additional collateral related to the
aforementioned bond for the fixed price natural gas sales contract. We have
entered into indemnification obligations in favor of the providers of these
surety bonds and letters of credit.
Other Guarantees and Credit Rating Triggers
We have various other guarantees for approximately $525 million. Approximately
$134 million of the $525 million in guarantees represent financial assurance we
gave on behalf of our Molycorp subsidiary relating to permits covering
operations and discharges from Molycorp's Questa, New Mexico, molybdenum mine.
Our financial assurance is for the completion of temporary closure plans
(required only upon cessation of operations) and other obligations required
under the terms of the permits. The costs associated with the financial
assurance are based on estimations provided by agencies of the state of New
Mexico.
Guarantees for approximately $300 million of the $525 million would require us
to obtain a surety bond or a letter of credit or establish a trust fund if our
credit rating were to drop below investment grade -- that is BBB- or Baa3 from
Standard & Poor's Ratings Services and Moody's Investors Service, Inc.,
respectively.
Classification on Balance Sheet
Approximately $150 million of the surety bonds, letters of credit and other
guarantees that we are required to obtain or issue reflect obligations that are
already included on the consolidated balance sheet in other current liabilities
and other deferred credits. The surety bonds, letters of credit and other
guarantees may also reflect some of the possible additional remediation
liabilities discussed earlier in this note.
Other Matters
Our lease agreement for the Discoverer Spirit deepwater drillship has a current
minimum daily rate of approximately $226,000. The future remaining minimum lease
payment obligation was approximately $80 million at September 30, 2004. The
contract will expire on September 18, 2005.
We also have other contingent liabilities for litigation, claims and contractual
agreements arising in the ordinary course of business. Based on management's
assessment of the ultimate amount and timing of possible adverse outcomes and
associated costs, none of these other matters is presently expected to have a
material adverse effect on our consolidated financial condition, liquidity or
results of operations.
-21-
18. Capital Stock
Treasury Stock: In the third quarter of 2004, we purchased 4,130,000 common
shares at a cost of $150 million. This tranche of the stock repurchase program
was originally approved in January 1998 when our Board of Directors extended the
repurchase program of common stock by $200 million, adding to the $400 million
of common stock it had authorized for repurchase in 1996.
In February 2004, we repurchased 539,208 shares of our common stock from four of
the original participants of the Executive Stock Purchase Program (the
"Program") of 2000 at market prices. The purchases, which aggregated to
approximately $20 million, were accounted for as treasury stock on the
consolidated balance sheet. The recipients used the proceeds to repay the loans
made by Unocal for the original acquisition of the shares (see note 19 for
further detail).
At September 30, 2004, we held 15,291,992 common shares as treasury stock at a
cost of $581 million. At December 31, 2003, we held 10,622,784 common shares at
a cost of $411 million.
19. Loans to Certain Officers and Key Employees
In February 2004, we repurchased 539,208 shares from four of the original
participants in our 2000 Executive Stock Purchase Program at market price for
approximately $20 million. The purchase of this number of shares was approved by
our board of directors in February 2004. The Program was approved by our board
of directors and by our stockholders at the annual stockholders meeting in May
2000. The balance of the loans under this Program, including accrued interest,
totaled $3 million at September 30, 2004 and $27 million at December 31, 2003,
and was reflected as a reduction to stockholders' equity on the consolidated
balance sheet.
20. Financial Instruments and Commodity Hedging
Interest rate contracts - We enter into interest rate swap contracts to manage
our debt with the objective of minimizing the volatility and magnitude of our
borrowing costs. We may also enter into interest rate option contracts to
protect our interest rate positions, depending on market conditions. At
September 30, 2004, we had approximately $21 million of after-tax deferred
losses in accumulated other comprehensive income on the consolidated balance
sheet related to cash flow hedges of interest rate exposures through September
2012. Of this amount, approximately $3 million in after-tax losses are expected
to be reclassified to the consolidated earnings statement during the next twelve
months.
Foreign currency contracts - Various foreign exchange currency forward, option
and swap contracts are entered into from time to time to manage our exposures to
adverse impacts of foreign currency fluctuations on recognized obligations and
anticipated transactions. At September 30, 2004, we had no material deferred
amounts in accumulated other comprehensive income on the consolidated balance
sheet related to foreign currency contracts.
Commodity hedging activities - We use hydrocarbon derivatives to mitigate our
overall exposure to fluctuations in hydrocarbon commodity prices. We reported a
gain of $1 million in the nine month period of 2004 due to ineffectiveness for
cash flow and fair value hedges. At September 30, 2004, we had approximately $40
million of after-tax deferred losses in accumulated other comprehensive income
on the consolidated balance sheet related to cash flow hedges for future
commodity sales for the period beginning October 2004 through December 2005.
Nearly all of the after-tax losses are expected to be reclassified to the
consolidated earnings statement during the next twelve months.
Fair values for debt and other long-term instruments - The estimated fair values
of our long-term debt were $3.37 billion at September 30, 2004. Fair values were
based on the discounted amounts of future cash outflows using the rates offered
to us for debt with similar remaining maturities.
-22-
21. Supplemental Condensed Consolidating Financial Information
Unocal guarantees all the publicly held securities issued by its 100
percent-owned subsidiary Union Oil. Such guarantees are full and unconditional
and no subsidiaries of Unocal or Union Oil guarantee these securities.
As a result of adopting FASB Interpretation No. 46 (revised December 2003) (see
note 2 and 15 for further detail), we deconsolidated Unocal Capital Trust
effective January 1, 2004.
The following tables present condensed consolidating financial information for
(a) Unocal (Parent), (b) Union Oil (Parent) and (c) on a combined basis, the
subsidiaries of Union Oil (non-guarantor subsidiaries). Virtually all of our
operations are conducted by Union Oil and its subsidiaries. The 2003 tables also
present the Trust, as part of the condensed consolidating financial information.
CONDENSED CONSOLIDATED EARNINGS STATEMENT
For the Three Months Ended September 30, 2004
Non-
Unocal Union Oil Guarantor
Millions of dollars (Parent) (Parent) Subsidiaries Eliminations Consolidated
----------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ 389 $ 1,850 $ (278) $ 1,961
Interest, dividends and miscellaneous income - 1 7 (2) 6
Gain on sales of assets - 24 2 - 26
----------------------------------------------------------------------------------------------------------------------
Total revenues - 414 1,859 (280) 1,993
Costs and other deductions
Purchases, operating and other expenses 4 299 1,168 (278) 1,193
Depreciation, depletion and amortization - 65 183 - 248
Impairments - 12 16 - 28
Dry hole costs - 3 9 - 12
Interest expense 11 22 9 (2) 40
----------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 15 401 1,385 (280) 1,521
Equity in earnings of subsidiaries 341 310 - (651) -
Earnings from equity investments - 1 30 - 31
----------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 326 324 504 (651) 503
----------------------------------------------------------------------------------------------------------------------
Income taxes (4) (17) 193 - 172
Minority interests - - 2 - 2
----------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 330 341 309 (651) 329
Earnings from discontinued operations - - 1 - 1
----------------------------------------------------------------------------------------------------------------------
Net earnings $ 330 $ 341 $ 310 $ (651) $ 330
======================================================================================================================
-23-
CONDENSED CONSOLIDATED EARNINGS STATEMENT
For the Three Months Ended September 30, 2003
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-----------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ - $ 339 $ 1,307 $ (174) $ 1,472
Interest, dividends and miscellaneous income - 8 (3) - (7) (2)
Gain on sales of assets - - 15 42 8 65
-----------------------------------------------------------------------------------------------------------------------
Total revenues - 8 351 1,349 (173) 1,535
Costs and other deductions
Purchases, operating and other expenses 4 - 254 815 (164) 909
Depreciation, depletion and amortization - - 61 170 - 231
Impairments - - 14 69 - 83
Dry hole costs - - 5 9 - 14
Interest expense 8 - 38 8 (9) 45
Distributions on convertible preferred securities - 8 - - - 8
-----------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 12 8 372 1,071 (173) 1,290
Equity in earnings of subsidiaries 161 - 189 - (350) -
Earnings from equity investments - - (1) 55 - 54
-----------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 149 - 167 333 (350) 299
-----------------------------------------------------------------------------------------------------------------------
Income taxes (3) - 6 142 - 145
Minority interests - - - 4 - 4
-----------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 152 - 161 187 (350) 150
Earnings from discontinued operations - - - 2 - 2
-----------------------------------------------------------------------------------------------------------------------
Net earnings $ 152 $ - $ 161 $ 189 $ (350) $ 152
=======================================================================================================================
-24-
CONDENSED CONSOLIDATED EARNINGS STATEMENT
For the Nine Months Ended September 30, 2004
Non-
Unocal Union Oil Guarantor
Millions of dollars (Parent) (Parent) Subsidiaries Eliminations Consolidated
---------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ 1,033 $ 5,393 $ (714) $ 5,712
Interest, dividends and miscellaneous income 1 6 34 (5) 36
Gain on sales of assets - 8 102 110
---------------------------------------------------------------------------------------------------------------------
Total revenues 1 1,047 5,529 (719) 5,858
Costs and other deductions
Purchases, operating and other expenses 9 820 3,506 (715) 3,620
Depreciation, depletion and amortization - 193 527 - 720
Impairments - 18 24 - 42
Dry hole costs - 30 47 - 77
Interest expense 28 79 25 (5) 127
Distributions on convertible preferred securities - - - - -
---------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 37 1,140 4,129 (720) 4,586
Equity in earnings of subsidiaries 969 991 - (1,960) -
Earnings from equity investments - 4 103 (1) 106
---------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 933 902 1,503 (1,960) 1,378
---------------------------------------------------------------------------------------------------------------------
Income taxes (7) (69) 571 495
Minority interests - 6 6
---------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 940 971 926 (1,960) 877
Earnings from discontinued operations - (2) 65 63
---------------------------------------------------------------------------------------------------------------------
Net earnings $ 940 $ 969 $ 991 $ (1,960) $ 940
=====================================================================================================================
-25-
CONDENSED CONSOLIDATED EARNINGS STATEMENT
For the Nine Months Ended September 30, 2003
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-----------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ - $ 1,212 $ 4,508 $ (923) $ 4,797
Interest, dividends and miscellaneous income - 25 15 6 (28) 18
Gain on sales of assets - - 49 58 8 115
-----------------------------------------------------------------------------------------------------------------------
Total revenues - 25 1,276 4,572 (943) 4,930
Costs and other deductions
Purchases, operating and other expenses 9 - 877 3,061 (914) 3,033
Depreciation, depletion and amortization - - 245 499 - 744
Impairments - - 17 69 - 86
Dry hole costs - - 63 32 - 95
Interest expense 25 1 97 25 (29) 119
Distributions on convertible preferred securities - 24 - - - 24
-----------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 34 25 1,299 3,686 (943) 4,101
Equity in earnings of subsidiaries 490 - 594 - (1,084) -
Earnings from equity investments - - 6 144 - 150
-----------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 456 - 577 1,030 (1,084) 979
-----------------------------------------------------------------------------------------------------------------------
Income taxes (7) - 40 409 - 442
Minority interests - - - 8 - 8
-----------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 463 - 537 613 (1,084) 529
Earnings from discontinued operations - - 8 9 - 17
Cumulative effects of accounting changes - - (55) (28) - (83)
-----------------------------------------------------------------------------------------------------------------------
Net earnings $ 463 $ - $ 490 $ 594 $ (1,084) $ 463
=======================================================================================================================
-26-
CONDENSED CONSOLIDATED BALANCE SHEET
At September 30, 2004
Non-
Unocal Union Oil Guarantor
Millions of dollars (Parent) (Parent) Subsidiaries Eliminations Consolidated
----------------------------------------------------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ - $ 227 $ 553 $ - $ 780
Accounts and notes receivable - net 117 382 987 (117) 1,369
Inventories - 7 269 (78) 198
Other current assets - 108 24 - 132
----------------------------------------------------------------------------------------------------------------------
Total current assets 117 724 1,833 (195) 2,479
Properties - net - 1,978 6,664 (3) 8,639
Other assets including goodwill 5,761 5,657 2,171 (12,187) 1,402
----------------------------------------------------------------------------------------------------------------------
Total assets $5,878 $ 8,359 $ 10,668 $ (12,385) $ 12,520
======================================================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ - $ 326 $ 915 $ (115) $ 1,126
Current portion of long-term debt - 162 73 - 235
Other current liabilities 54 316 434 (2) 802
----------------------------------------------------------------------------------------------------------------------
Total current liabilities 54 804 1,422 (117) 2,163
Long-term debt and capital leases 269 1,648 925 - 2,842
Deferred income taxes - (205) 942 - 737
Accrued abandonment, restoration
and environmental liabilities - 382 509 - 891
Other deferred credits and liabilities 1 672 347 (4) 1,016
Minority interests - - 24 13 37
Stockholders' equity 5,554 5,058 6,499 (12,277) 4,834
----------------------------------------------------------------------------------------------------------------------
Total liabilities and stockholders' equity $5,878 $ 8,359 $ 10,668 $ (12,385) $ 12,520
======================================================================================================================
-27-
CONDENSED CONSOLIDATED BALANCE SHEET
At December 31, 2003
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
------------------------------------------------------------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ 1 $ - $ 45 $ 358 $ - $ 404
Accounts and notes receivable - net 94 - 360 946 (108) 1,292
Inventories - - 15 205 (79) 141
Other current assets (1) - 127 28 - 154
------------------------------------------------------------------------------------------------------------------------------
Total current assets 94 - 547 1,537 (187) 1,991
Properties - net - - 2,012 6,315 (3) 8,324
Other assets including goodwill 4,645 541 5,433 1,564 (10,700) 1,483
------------------------------------------------------------------------------------------------------------------------------
Total assets $4,739 $ 541 $ 7,992 $ 9,416 $ (10,890) $ 11,798
==============================================================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ - $ - $ 335 $ 831 $ (94) $ 1,072
Current portion of long-term debt - - 193 55 - 248
Other current liabilities 52 3 299 427 (16) 765
------------------------------------------------------------------------------------------------------------------------------
Total current liabilities 52 3 827 1,313 (110) 2,085
Long-term debt - - 1,811 824 - 2,635
Deferred income taxes - - (184) 888 - 704
Accrued abandonment, restoration
and environmental liabilities - - 390 454 - 844
Other deferred credits and liabilities - - 654 309 (3) 960
Minority interests - - - 32 7 39
Company-obligated mandatorily redeemable
convertible preferred securities of a
subsidiary trust holding solely parent debentures - 522 - - - 522
Stockholders' equity 4,687 16 4,494 5,596 (10,784) 4,009
------------------------------------------------------------------------------------------------------------------------------
Total liabilities and stockholders' equity $4,739 $ 541 $ 7,992 $ 9,416 $ (10,890) $ 11,798
==============================================================================================================================
-28-
CONDENSED CONSOLIDATED CASH FLOWS
For the Nine Months Ended September 30, 2004
Non-
Unocal Union Oil Guarantor
Millions of dollars (Parent) (Parent) Subsidiaries Eliminations Consolidated
---------------------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities $ 407 $ 575 $ 710 $ - $ 1,692
Cash Flows from Investing Activities
Capital expenditures and acquisitions
(includes dry hole costs) - (262) (981) - (1,243)
Proceeds from sales of assets
and discontinued operations - 64 337 - 401
Return of capital from affiliate company - - 48 - 48
---------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities - (198) (596) - (794)
---------------------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Change in long-term debt - (193) 83 - (110)
Dividends paid on common stock (158) - - - (158)
Minority interests - - (2) - (2)
Proceeds from issuance of common stock 149 - - - 149
Repurchases of common stock (170) - - - (170)
Repurchases of preferred securities (253) - - - (253)
Other 24 (2) - - 22
---------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities (408) (195) 81 - (522)
---------------------------------------------------------------------------------------------------------------------
Increase (decrease) in cash and cash equivalents (1) 182 195 - 376
---------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at beginning of period 1 45 358 - 404
---------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ - $ 227 $ 553 $ - $ 780
=====================================================================================================================
CONDENSED CONSOLIDATED CASH FLOWS
For the Nine Months Ended September 30, 2003
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
--------------------------------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities $ 130 $ - $ 417 $ 1,106 $ - $ 1,653
Cash Flows from Investing Activities
Capital expenditures and acquisitions
(includes dry hole costs) - - (336) (960) - (1,296)
Proceeds from sales of assets
and discontinued operations - - 150 204 - 354
--------------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities - - (186) (756) - (942)
--------------------------------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Change in long-term debt and capital leases - - (114) 112 - (2)
Dividends paid on common stock (155) - - - - (155)
Minority interests - - - (257) - (257)
Proceeds from issuance of common stock 15 - - - - 15
Other 10 - - (5) - 5
--------------------------------------------------------------------------------------------------------------------------------
Net cash used in financing activities (130) - (114) (150) - (394)
--------------------------------------------------------------------------------------------------------------------------------
Increase in cash and cash equivalents - - 117 200 - 317
--------------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at beginning of period - - (18) 186 - 168
--------------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ - $ - $ 99 $ 386 $ - $ 485
================================================================================================================================
-29-
22. Segment Data
We made changes in the reporting of our segments from the reporting utilized in
the 2003 Annual Report on Form 10-K, as amended, as detailed in the following
tables. Our reportable segments are: (1) Exploration and Production, (2)
Midstream and Marketing, and (3) Geothermal. General corporate overhead,
unallocated costs and other miscellaneous operations, including real estate,
carbon and minerals and those businesses that were sold or being phased-out, are
included under the Corporate and Other heading.
Our Exploration and Production segment has simplified its North America
presentation by combining the Alaska business unit with the U.S. Lower 48
business to form the U.S. geographic designation. In the International
geographic designation, we now present Asia and Other, instead of the previous
categories of Far East and Other. In addition, the former Trade segment has been
combined with the Midstream segment to form the Midstream and Marketing segment.
----------------------------------------------------------------------------------------------------------------------
Segment Information Exploration and Production
For the Three Months North America International
Ended September 30, 2004
----------------------------------------------------------------------------------------------------------------------
Millions of dollars U.S. Canada Total N.A. Asia Other Total Int'l Total E&P
----------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 204 $ 80 $ 284 $ 394 $ 70 $ 464 $ 748
Other income (loss) (a) (2) - (2) 2 1 3 1
Inter-segment revenues 279 34 313 155 - 155 468
----------------------------------------------------------------------------------------------------------------------
Total 481 114 595 551 71 622 1,217
Earnings (loss) from equity investments - - - 11 1 12 12
Earnings (loss) from continuing operations 97 15 112 189 31 220 332
Earnings from discontinued operations (net) 1 - 1 - - - 1
----------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 98 15 113 189 31 220 333
Assets (at September 30, 2004) 3,164 1,333 4,497 3,574 941 4,515 9,012
----------------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------------
Midstream Geothermal Corporate and Other Total
and Net Environ-
Marketing Admin & Interest mental &
General Expense Litigation Other(b)
----------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 1,096 $ 38 $ - $ - $ - $ 79 $ 1,961
Other income (loss) (a) 2 - - 3 - 26 32
Inter-segment revenues 2 - - - - (470) -
----------------------------------------------------------------------------------------------------------------------
Total 1,100 38 - 3 - (365) 1,993
Earnings (loss) from equity investments 10 - - - - 9 31
Earnings (loss) from continuing operations 12 3 (19) (26) (20) 47 329
Earnings from discontinued operations (net) - - - - - - 1
----------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 12 3 (19) (26) (20) 47 330
Assets (at September 30, 2004) 1,210 528 - - - 1,770 12,520
----------------------------------------------------------------------------------------------------------------------
(a) Includes interest, dividends and miscellaneous income, and gain (loss) on
sales of assets.
(b) Includes eliminations and consolidation adjustments.
-30-
----------------------------------------------------------------------------------------------------------------------
Segment Information Exploration and Production
For the Three Months North America International
Ended September 30, 2003
----------------------------------------------------------------------------------------------------------------------
Millions of dollars U.S. Canada Total N.A. Asia Other Total Int'l Total E&P
----------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 205 $ 39 $ 244 $ 329 $ 49 $ 378 $ 622
Other income (loss) (a) 47 12 59 - 1 1 60
Inter-segment revenues 248 36 284 67 - 67 351
----------------------------------------------------------------------------------------------------------------------
Total 500 87 587 396 50 446 1,033
Earnings (loss) from equity investments 6 - 6 12 1 13 19
Earnings (loss) from continuing operations 87 15 102 113 23 136 238
Earnings from discontinued operations (net) 1 - 1 - - - 1
----------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 88 15 103 113 23 136 239
Assets (at December 31, 2003) 3,315 1,324 4,639 3,377 765 4,142 8,781
----------------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------------
Midstream Geothermal Corporate and Other Total
and Net Environ-
Marketing Admin & Interest mental &
General Expense Litigation Other(b)
----------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 774 $ 41 $ - $ - $ - $ 35 $ 1,472
Other income (loss) (a) 5 2 - (4) - - 63
Inter-segment revenues 2 - - - - (353) -
----------------------------------------------------------------------------------------------------------------------
Total 781 43 - (4) - (318) 1,535
Earnings (loss) from equity investments 18 5 - - - 12 54
Earnings (loss) from continuing operations 19 19 (21) (32) (33) (40) 150
Earnings from discontinued operations (net) 1 - - - - - 2
----------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 20 19 (21) (32) (33) (40) 152
Assets (at December 31, 2003) 1,097 611 - - - 1,309 11,798
----------------------------------------------------------------------------------------------------------------------
(a) Includes interest, dividends and miscellaneous income, and gain (loss) on
sales of assets.
(b) Includes eliminations and consolidation adjustments.
-31-
----------------------------------------------------------------------------------------------------------------------
Segment Information Exploration and Production
For the Nine Months North America International
Ended September 30, 2004
----------------------------------------------------------------------------------------------------------------------
Millions of dollars U.S. Canada Total N.A. Asia Other Total Int'l Total E&P
----------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 699 $ 219 $ 918 $1,102 $ 206 $1,308 $ 2,226
Other income (loss) (a) 43 - 43 4 3 7 50
Inter-segment revenues 714 100 814 357 - 357 1,171
----------------------------------------------------------------------------------------------------------------------
Total 1,456 319 1,775 1,463 209 1,672 3,447
Earnings (loss) from equity investments - - - 33 3 36 36
Earnings (loss) from continuing operations 318 43 361 484 77 561 922
Earnings from discontinued operations (net) 50 - 50 - - - 50
----------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 368 43 411 484 77 561 972
Assets (at September 30, 2004) 3,164 1,333 4,497 3,574 941 4,515 9,012
----------------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------------
Midstream Geothermal Corporate and Other Total
and Net Environ-
Marketing Admin & Interest mental &
General Expense Litigation Other(b)
----------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 3,080 $ 202 $ - $ - $ - $ 204 $ 5,712
Other income (loss) (a) 10 45 - 13 - 28 146
Inter-segment revenues 8 - - - - (1,179) -
----------------------------------------------------------------------------------------------------------------------
Total 3,098 247 - 13 - (947) 5,858
Earnings (loss) from equity investments 38 (1) - - - 33 106
Earnings (loss) from continuing operations 53 97 (67) (91) (47) 10 877
Earnings from discontinued operations (net) 13 - - - - - 63
----------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 66 97 (67) (91) (47) 10 640
Assets (at September 30, 2004) 1,210 528 - - - 1,770 12,520
----------------------------------------------------------------------------------------------------------------------
(a) Includes interest, dividends and miscellaneous income, and gain (loss) on
sales of assets.
(b) Includes eliminations and consolidation adjustments.
-32-
----------------------------------------------------------------------------------------------------------------------
Segment Information Exploration and Production
For the Nine Months North America International
Ended September 30, 2003
----------------------------------------------------------------------------------------------------------------------
Millions of dollars U.S. Canada Total N.A. Asia Other Total Int'l Total E&P
----------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 622 $134 $ 756 $ 982 $145 $1,127 $ 1,883
Other income (loss) (a) 96 12 108 - 1 1 109
Inter-segment revenues 920 115 1,035 230 - 230 1,265
----------------------------------------------------------------------------------------------------------------------
Total 1,638 261 1,899 1,212 146 1,358 3,257
Earnings (loss) from equity investments 15 - 15 32 5 37 52
Earnings (loss) from continuing operations 310 47 357 371 52 423 780
Earnings from discontinued operations (net) 8 - 8 - - - 8
Cumulative effect of accounting changes (b) (32) 4 (28) 13 - 13 (15)
----------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 286 51 337 384 52 436 773
Assets (at December 31, 2003) 3,315 1,324 4,639 3,377 765 4,142 8,781
----------------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------------
Midstream Geothermal Corporate and Other Total
and Net Environ-
Marketing Admin & Interest mental &
General Expense Litigation Other(c)
----------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 2,700 $104 $ - $ - $ - $110 $ 4,797
Other income (loss) (a) 6 4 - 6 - 8 133
Inter-segment revenues 7 - - - - (1,272) -
----------------------------------------------------------------------------------------------------------------------
Total 2,713 108 - 6 - (1,154) 4,930
Earnings (loss) from equity investments 51 10 - - - 37 150
Earnings (loss) from continuing operations 49 38 (66) (91) (78) (103) 529
Earnings from discontinued operations (net) 1 - - - - 8 17
Cumulative effect of accounting changes (b) (2) - - - - (66) (83)
----------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 48 38 (66) (91) (78) (161) 463
Assets (at December 31, 2003) 1,097 611 - - - 1,309 11,798
----------------------------------------------------------------------------------------------------------------------
(a) Includes interest, dividends and miscellaneous income, and gain (loss) on
sales of assets.
(b) Net of tax (benefit) $48
(c) Includes eliminations and consolidation adjustments.
-33-
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
You should read the following discussion and analysis of our financial condition
and results of operations in conjunction with Management's Discussion and
Analysis in Item 7 of Unocal's 2003 Annual Report on Form 10-K, as amended, and
the consolidated financial statements and related notes therein and Management's
Discussion and Analysis in Item 2 of Unocal's 2004 first and second quarterly
reports on Form 10-Q and the interim consolidated financial statements and
related notes therein. Our 2003 Annual Report on Form 10-K contains a discussion
of other matters not included herein, such as disclosures regarding critical
accounting policies and estimates and contractual obligations. You should read
the following discussion and analysis together with the cautionary statement
under "Forward-Looking Statements" on page iii of this report.
We simplified our reporting segments effective January 1, 2004. In our
Exploration and Production segment: (1) we combined the Alaska business unit
with the U.S. Lower 48 to form the U.S. geographic designation under North
America and (2) we now present Asia and Other instead of the previous categories
of Far East and Other under International. In addition, the former Trade segment
has been combined with the Midstream segment to form the Midstream and Marketing
segment. See note 22 to the consolidated financial statements in Item 1 of this
report for revisions to our reportable segments.
OVERVIEW
Unocal's primary line of business is the exploration, development and production
of natural gas, crude oil, condensate and natural gas liquids. Our principal
operations are in Asia and North America. We are also a leading producer of
geothermal energy and a provider of electrical power in Asia. Other activities
include ownership in proprietary and common carrier pipelines, natural gas
storage facilities and the marketing of hydrocarbon commodities. Our strategy is
focused on creating value for our stockholders by continuing to advance oil and
gas development projects and delivering successful exploration results through
the drill bit. Fluctuations in hydrocarbon commodity prices and the resulting
impact on our realized prices for liquids and North America natural gas are a
significant driver of our financial performance.
Some of our more significant operational highlights and other activities from
the third quarter of 2004 are listed below:
- completed the buyback of $150 million of Unocal common stock, redeemed $269
million of our outstanding 6-1/4% convertible junior subordinated debentures
and made a contribution of $100 million to our U.S. qualified pension plan,
- ramp-up of production continued on the deepwater West Seno project in
Indonesia, and the field was producing about 39 MBOE/d (gross) at the end of
September,
- AIOC participant companies approved and sanctioned Phase 3 development of
the Azeri-Chirag-Deepwater Gunashli ("ACG") field in the Azerbaijan sector
of the Caspian Sea. Phase 1 and Phase 2 of the project were sanctioned in
2001 and 2002, respectively,
- construction of the Phase 1 and 2 developments of the AIOC project in the
Caspian Sea progressed; first oil at the wellhead is expected in early 2005
for Phase 1,
- approximately 85 percent of the construction completed on the
Baku-Tbilisi-Ceyhan ("BTC") export pipeline from the Caspian Sea,
- $67 million received in cash from the sale of our 50 percent equity
interest in a jointly held project company that owned UnoPaso Exploracao e
Producao de Petroleo e Gas Ltda., a Brazilian exploration and production
venture that owned our remaining oil and natural gas assets in Brazil;
possible future payments contingent on achieving certain natural gas prices
and/or volume thresholds,
- deepwater appraisal wells encountered hydrocarbons on the St. Malo prospect
in the Gulf of Mexico and on the deepwater Ranggas, Gehem and Gula prospects
in Indonesia,
- completed the deepwater Gulf of Mexico Sardinia well as a dry hole but
encountered significant porous sandstones,
- completed successful delineation drilling in the South Gomin operating area
in the Gulf of Thailand, and
- elected not to proceed with our participation in five contracts to explore
for, develop and market natural gas resources in the Xihu Trough off the
coast of Shanghai, in the East China Sea.
-34-
CONSOLIDATED RESULTS
The following table summarizes our consolidated net earnings for the third
quarter and nine month periods ended September 30, 2004 and 2003:
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
--------------------------------------------
Millions of dollars 2004 2003 2004 2003
--------------------------------------------------------------------------------
Earnings from continuing operations $ 329 $ 150 $ 877 $ 529
Earnings from discontinued operations 1 2 63 17
Cumulative effect of accounting changes - - - (83)
--------------------------------------------------------------------------------
Net earnings $ 330 $ 152 $ 940 $ 463
================================================================================
Earnings From Continuing Operations
Third Quarter Results: Earnings from continuing operations were $329 million in
the third quarter of 2004, which was an increase of $179 million compared to the
same quarter a year ago. The increase was primarily due to higher realized
worldwide liquids and natural gas prices, which increased net earnings by
approximately $90 million and $30 million, respectively. In the current quarter,
our worldwide average realized liquids price was $38.85 per Bbl, which was an
increase of $11.57 per Bbl from the $27.28 per Bbl realized in the same period a
year ago. Our hedging program lowered the average realized liquids price by
$1.51 per Bbl in the current quarter while the prior year quarter included a
loss of 6 cents per Bbl from hedging activities. Our worldwide average realized
natural gas price, which included a loss of 3 cents per Mcf from hedging
activities in the current quarter, was $3.90 per Mcf. This was an increase of 30
cents per Mcf from the $3.60 per Mcf price realized during the same period a
year ago. There was not any effect on natural gas prices from hedging activities
in the third quarter of 2003. The results of the third quarter of 2004 reflect a
net tax benefit of $32 million relating primarily to settlements and assessments
with various taxing authorities and $13 million in higher tax benefits primarily
due to currency related adjustments in Thailand. After-tax impairments were
approximately $30 million lower in the third quarter of 2004 compared to the
same period a year ago. This was primarily due to the impairments in 2003
related to the assets that were held for sale in the Gulf of Mexico, partially
offset by an impairment in the third quarter of 2004 of our equity interest
investment in a gas-fired power plant and an impairment related to warehouse
stock for our Gulf of Mexico operations (see note 5 - Impairment of Assets). Our
after-tax environmental and litigation expenses were $21 million in the third
quarter of 2004, compared with $38 million in 2003, primarily reflecting lower
outside litigation support costs. In addition, the third quarter of 2003
included a $6 million after-tax charge related to our 2003 restructuring plan.
International liquids production was higher in the current quarter than the
prior year quarter primarily from Indonesia and Thailand, which increased net
earnings by approximately $15 million.
These positive variance factors were partially offset by lower North America
production, which reduced net earnings by approximately $60 million in the third
quarter of 2004 compared with the same period a year ago. The decline in North
America production was due primarily to the sale of oil and gas producing
assets. The third quarter of 2004 included approximately $17 million in
after-tax gains from asset sales, primarily from the sale of non-oil and gas
property in Parachute, Colorado, while the third quarter of 2003 included
after-tax gains on asset sales of approximately $35 million related primarily to
the sale of the majority of our shares in Tom Brown, Inc. ("Tom Brown").
Nine Months Results: Earnings from continuing operations were $877 million in
the nine month period of 2004 compared to $529 million for the same period a
year ago. The increase was primarily due to higher worldwide liquids and natural
gas prices, which increased net earnings by approximately $160 million and $90
million, respectively. In the nine month period of 2004, our worldwide average
realized liquids price was $33.85 per Bbl, which was an increase of $6.49 per
Bbl, or 24 percent, from the same period a year ago. Our average realized
liquids price included losses from our hedging activities of $1.47 per Bbl in
the nine month period of 2004 while the nine month period of 2003 included a
loss of 19 cents per Bbl from hedging activities. Our worldwide average realized
natural gas price, including a gain of one cent per Mcf from hedging activities,
was $3.92 per Mcf in the nine month period of 2004. This was an increase of 24
cents per Mcf, or 7 percent, from the $3.68 per Mcf, including a loss of 11
cents per Mcf from hedging activities, realized during the nine month period of
2003. International liquids production was higher in the nine month period of
2004 compared to the same period a year ago primarily from Indonesia and
Thailand, which increased net earnings by
-35-
approximately $30 million. Exploration expenses and dry hole costs were lower in
the nine month period of 2004 compared with the same period a year ago,
primarily due to lower amortization of exploratory leasehold costs and lower
drilling activity, increasing net earnings by approximately $35 million. In
addition, the nine month period of 2004 included an after-tax gain of $46
million from the settlement of an outstanding eight-year dispute over operation
of the Tiwi and Mak-Ban geothermal steam fields in the Philippines. The nine
month period of 2004 reflects net tax benefits of $60 million relating primarily
to settlements and assessments with various taxing authorities and $32 million
in higher tax benefits primarily due to currency related adjustments in
Thailand. After-tax impairments were approximately $24 million lower in the nine
month period of 2004 compared to the same period a year ago. This was primarily
due to the impairments in 2003 related to the assets that were held for sale in
the Gulf of Mexico, partially offset by an impairment of our equity interest
investment in a gas-fired power plant and an impairment related to warehouse
stock for our Gulf of Mexico operations (see note 5 - Impairment of Assets).
After-tax environmental and litigation expenses were $59 million in the nine
month period of 2004, compared with $83 million in the same period a year ago.
The nine month period of 2004 also included a $1 million after-tax benefit from
an adjustment to the 2003 company-wide restructuring plan, for which we recorded
charges totaling $23 million in 2003. The nine month period of 2004 included
approximately $70 million in after-tax gains from asset sales, primarily from
the sale of certain of our exploratory mineral fee lands in the U.S., the sale
of our rights and interests in the Sarulla geothermal project on the island of
Sumatra, Indonesia, the sale of non-oil and gas property in Parachute, Colorado
and other miscellaneous real estate properties. The nine month period of 2003
included after-tax gains of approximately $60 million from asset sales,
including the sale of all of our stock holding in Matador Petroleum Corporation
("Matador"), the majority of our shares in Tom Brown held at that time and
miscellaneous property in Canada.
These positive variance factors were partially offset by lower North America
production, which reduced net earnings by approximately $170 million in the nine
month period of 2004. We also recorded a provision of $46 million pre-tax ($29
million after-tax) associated with the recent arbitration ruling regarding
Agrium's Kenai, Alaska nitrogen-based fertilizer plant, and our obligations to
supply natural gas to the plant.
Earnings From Discontinued Operations
Earnings from discontinued operations were $1 million and $2 million in the
third quarters of 2004 and 2003, respectively, and $63 million and $17 million
for the nine month periods of 2004 and 2003, respectively.
The nine month period of 2004 included approximately $44 million after-tax from
our sale of certain mineral fee producing properties in the U.S. and $13 million
after-tax from our sale of the Cal Ven pipeline located in Alberta, Canada. The
remaining amounts in the nine month period of 2004 reflect after-tax earnings of
$6 million from our operations in these mineral fee producing properties and the
Cal Ven pipeline prior to sale. After-tax earnings from the mineral fee
producing properties and the Cal Ven pipeline were $2 million and $9 million
during the third quarter and nine month periods of 2003, respectively.
The nine month period of 2003 included an after-tax gain of $8 million related
to the 1997 sale of our former West Coast refining, marketing and transportation
assets. The sales agreement contained a provision calling for payments to us for
price differences between California Air Resources Board Phase 2 gasoline and
conventional gasoline. This provision of the agreement terminated at the end of
2003.
Cumulative Effect of Accounting Changes
In the first quarter of 2003, we recorded a non-cash $83 million after-tax
charge for the cumulative effect of a change in accounting principle related to
the initial adoption of Statement of Financial Accounting Standards ("SFAS") No.
143, "Accounting for Asset Retirement Obligations."
Revenues
Revenues from continuing operations for the third quarter of 2004 were $1.99
billion compared with $1.54 billion for the same period a year ago. In the nine
month period of 2004, total revenues from continuing operations were $5.86
billion compared with $4.93 billion for the same period a year ago. The increase
in both the third quarter and nine month periods primarily reflected higher
crude oil and natural gas prices. This was partially offset by lower North
America production.
-36-
Income Taxes
Income taxes on earnings from continuing operations for the third quarter and
nine month periods of 2004 were $172 million and $495 million, respectively,
compared with $145 million and $442 million for the comparable periods of 2003.
The effective income tax rate for the third quarter and nine month periods of
2004 was 34 percent and 36 percent, respectively, compared with 48 percent and
45 percent, for each of the third quarter and nine month periods of 2003,
respectively. The overall lower effective tax rates for both the third quarter
and nine month periods of 2004, as compared to the periods a year ago, are due
primarily to a net tax benefit of $32 million in the third quarter of 2004 and
$60 million for the nine month period of 2004 relating primarily to settlements
and assessments with various taxing authorities and the tax benefit effect in
2004 of currency related adjustments in Thailand.
Operating Highlights
The following table summarizes our net daily production and average prices for
our North America and International Exploration and Production business units:
OPERATING HIGHLIGHTS
For the For the
Three Months Nine Months
Ended September 30,Ended September 30,
--------------------------------------
2004 2003 2004 2003
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North America Net Daily Production
Liquids (thousand barrels)
U.S. (a) 51 63 54 67
Canada 16 17 16 17
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Total liquids 67 80 70 84
Natural gas - dry basis (million cubic feet)
U.S. (a) 486 644 503 709
Canada 83 90 83 91
-----------------------------------------------------------------------------------
Total natural gas 569 734 586 800
North America Average Prices (excluding hedging activities) (b)
Liquids (per barrel)
U. S. $ 40.37 $ 28.41 $ 35.77 $ 28.64
Canada $ 35.43 $ 24.02 $ 31.22 $ 25.37
Average $ 39.23 $ 27.47 $ 34.75 $ 27.96
Natural gas (per mcf)
U. S. $ 5.13 $ 4.52 $ 5.12 $ 5.03
Canada $ 5.23 $ 4.96 $ 5.32 $ 5.24
Average $ 5.14 $ 4.57 $ 5.15 $ 5.05
-----------------------------------------------------------------------------------
North America Average Prices (including hedging activities) (b)
Liquids (per barrel)
U. S. $ 35.97 $ 28.27 $ 31.63 $ 28.18
Canada $ 35.43 $ 24.02 $ 31.22 $ 25.37
Average $ 35.85 $ 27.36 $ 31.54 $ 27.59
Natural gas (per mcf)
U. S. $ 5.06 $ 4.56 $ 5.19 $ 4.78
Canada $ 5.01 $ 4.64 $ 5.04 $ 4.93
Average $ 5.05 $ 4.57 $ 5.17 $ 4.79
-----------------------------------------------------------------------------------
(a) Includes proportional interests in production of equity investees.
(b) Excludes gains/losses on derivative positions not accounted for as hedges
and ineffective portions of hedges.
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OPERATING HIGHLIGHTS (CONTINUED)
For the For the
Three Months Nine Months
Ended September 30,Ended September 30,
--------------------------------------
2004 2003 2004 2003
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International Net Daily Production (c)
Liquids (thousand barrels)
Asia 70 59 66 58
Other (a) 18 20 19 20
-----------------------------------------------------------------------------------
Total liquids 88 79 85 78
Natural gas - dry basis (million cubic feet)
Asia 927 934 888 956
Other (a) 15 23 24 23
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Total natural gas 942 957 912 979
International Average Prices (d)
Liquids (per barrel)
Asia $ 41.04 $ 26.64 $ 35.58 $ 26.92
Other $ 42.33 $ 29.25 $ 36.63 $ 27.76
Average $ 41.27 $ 27.20 $ 35.80 $ 27.11
Natural gas (per mcf)
Asia $ 3.19 $ 2.86 $ 3.09 $ 2.79
Other $ 4.21 $ 4.57 $ 4.18 $ 4.45
Average $ 3.20 $ 2.87 $ 3.10 $ 2.80
-----------------------------------------------------------------------------------
-----------------------------------------------------------------------------------
Worldwide Net Daily Production (a) (c)
Liquids (thousand barrels) 155 159 155 162
Natural gas - dry basis (million cubic feet) 1,511 1,691 1,498 1,779
Barrels oil equivalent (thousands) 407 441 405 458
Worldwide Average Prices (excluding hedging activities) (b)
Liquids (per barrel) $ 40.36 $ 27.34 $ 35.32 $ 27.55
Natural gas (per mcf) $ 3.93 $ 3.60 $ 3.91 $ 3.79
Worldwide Average Prices (including hedging activities) (b)
Liquids (per barrel) $ 38.85 $ 27.28 $ 33.85 $ 27.36
Natural gas (per mcf) $ 3.90 $ 3.60 $ 3.92 $ 3.68
-----------------------------------------------------------------------------------
(a) Includes proportional interests in production of equity investees.
(b) Excludes gains/losses on derivative positions not accounted for as hedges
and ineffective portions of hedges.
(c) International production is presented utilizing the economic interest method.
(d) International did not have any hedging activities.
-38-
BUSINESS SEGMENT RESULTS
See note 22 to the consolidated financial statements in Item 1 of this report
for an explanation of changes to our reportable segments effective as of January
1, 2004, which are organized as follows:
Exploration and Production
We engage in oil and gas exploration, development and production worldwide. The
results of this segment are discussed under the geographical breakdown of North
America and International:
North America - Included in this category are the U.S. and Canada oil and gas
operations.
Third Quarter Results: After-tax earnings totaled $112 million in the third
quarter of 2004 compared to $102 million for the same period a year ago, which
was an increase of $10 million. Higher natural gas and liquids prices
contributed $50 million in higher earnings in the third quarter of 2004 compared
with the quarter a year ago. After-tax impairments were approximately $8 million
in the third quarter of 2004 compared to $48 million in the same period a year
ago. This decrease was primarily due to the impairments in 2003 related to the
assets that were held for sale in the Gulf of Mexico. The positive impact from
higher prices and lower impairments was offset by lower natural gas and liquids
production in the third quarter of 2004 compared with the same period a year
ago, which reduced after-tax earnings by approximately $60 million. North
America liquids production averaged 67,000 Bbl/d in the third quarter of 2004,
down from 80,000 Bbl/d a year ago, while natural gas production averaged 569
MMcf/d down from 734 MMcf/d in 2003. Most of the production decline was due to
the divestiture of various properties in the Gulf of Mexico, onshore U.S. and
Canada in 2003. In addition, the third quarter of 2003 included approximately
$30 million after-tax in gains on asset sales primarily from the sale of the
majority of our shares in Tom Brown.
Nine Months Results: After-tax earnings totaled $361 million in the nine month
period of 2004 compared to $357 million for the same period a year ago, which
was an increase of $4 million. Higher natural gas and liquids prices increased
net earnings by approximately $110 million in the nine month period of 2004
compared with the same period a year ago. In addition, exploration expenses and
dry hole costs were lower in the nine month period of 2004 compared with the
same period a year ago, primarily due to lower amortization of exploratory
leasehold costs and lower drilling activity, which increased net earnings by
approximately $50 million. After-tax impairments were approximately $13 million
in the nine month period of 2004 compared to $49 million in the same period a
year ago. This decrease was primarily due to the impairments in 2003 related to
the assets that were held for sale in the Gulf of Mexico. The nine month period
of 2004 also included a $15 million litigation settlement related to a previous
asset sale.
These positive factors were partially offset by lower natural gas and liquids
production in the nine month period of 2004 compared to the same period a year
ago, which reduced after-tax earnings by approximately $170 million. North
America liquids production averaged 70,000 Bbl/d in the nine month period of
2004, down from 84,000 Bbl/d a year ago, while natural gas production averaged
586 MMcf/d down from 800 MMcf/d for the nine month period a year ago. Most of
the production decline was due to the divestiture of various properties in the
Gulf of Mexico, onshore U.S. and Canada in 2003. The nine month period of 2004
included approximately $27 million after-tax in asset sale gains, primarily from
the sale of certain of our exploratory mineral fee lands in the U.S. The nine
month results of 2003 included $55 million after-tax in asset sale gains,
primarily from the sale of all of our stock holding in Matador and the majority
of our shares in Tom Brown and miscellaneous property in Canada. In addition,
the sale of our equity investments in Matador and Tom Brown in 2003 reduced net
earnings by $10 million in 2004 as compared to 2003.
International - Our International operations encompass oil and gas exploration
and production activities outside of North America. Through our International
subsidiaries, we operate or participate in production operations in Thailand,
Indonesia, Myanmar, Bangladesh, the Netherlands, Azerbaijan and the Democratic
Republic of Congo.
Third Quarter Results: After-tax earnings totaled $220 million in the third
quarter of 2004 compared to $136 million in the third quarter of 2003. The
increase was primarily due to higher liquids and natural gas prices, which
increased net earnings by approximately $55 million and $10 million,
respectively. In addition, higher production principally from Indonesia and
Thailand contributed approximately $15 million to after-tax earnings. The
results of the third quarter of 2004 reflect higher net tax benefits of $10
million primarily due to currency related adjustments in Thailand as compared to
the same period a year ago. These positive factors were partially offset by a
$10 million after-tax charge
-39-
for the relinquishment of lands and provision for settlement of obligations
related to the termination of our participation in five contracts to explore
for, develop and market natural gas resources in the Xihu Trough off the coast
of Shanghai, in the East China Sea.
Nine Months Results: After-tax earnings totaled $561 million in the nine month
period of 2004 compared to $423 million in the nine month period of 2003. The
increase was primarily due to higher liquids and natural gas prices, which
increased net earnings by approximately $110 million and $30 million,
respectively. Higher liquids production benefited the 2004 results by adding
approximately $30 million to net earnings and was primarily due to higher West
Seno production in Indonesia. The nine month period of 2004 reflects higher net
tax benefits as compared to the same period a year ago, which increased
after-tax earnings by approximately $25 million due to currency related
adjustments in Thailand. These positive factors were partially offset by lower
natural gas production primarily from Myanmar, which reduced after-tax earnings
by approximately $15 million. The nine month period of 2004 results reflected
higher operating expenses, primarily from Indonesia, as compared to the same
period a year ago, which reduced net earnings by $15 million. Higher dry hole
costs, primarily from Indonesia and Thailand, in the nine month period of 2004,
as compared with the same period a year ago, reduced net earnings by
approximately $10 million. In addition, the nine month period of 2004 included
the aforementioned $10 million after-tax charge related to the termination of
our participation in the exploration and development of the Xihu Trough in
China.
Midstream and Marketing
The Midstream and Marketing segment is comprised of our equity interests in
certain petroleum pipeline companies, wholly-owned pipelines and terminals
throughout the U.S., our North America gas storage business and the organization
that markets the majority of our worldwide liquids production and North American
natural gas production. In addition, the marketing organization conducts our
trading activities involving hydrocarbon derivative instruments, for which hedge
accounting is not used, to exploit anticipated opportunities arising from
commodity price fluctuations. The marketing organization also purchases limited
amounts of physical inventories for energy trading purposes when arbitrage
opportunities arise. These commodity risk-management and trading activities are
subject to internal restrictions, including value at risk limits, which measure
our potential loss from likely changes in market prices.
Third Quarter Results: Earnings from continuing operations totaled $12 million
in the current quarter compared to $19 million in the third quarter of 2003. The
results for the third quarter of 2004 reflect lower earnings from our pipeline
business. The third quarter of 2003 results reflected a gain on the sale of a
domestic pipeline asset. The third quarter of 2004 results included a $3 million
after-tax write-off related to a project to develop an offshore bulk oil
transfer system in the western Gulf of Mexico. The third quarter of 2003 results
included a $4 million after-tax in impairment related to our investment in the
Trans-Andean oil pipeline, which transports crude oil from Argentina to Chile.
The segment's sales and operating revenues were $1.1 billion in the current
quarter compared to $776 million in the same quarter a year ago. Included in
these totals were sales from marketing activities totaling $920 million in the
current quarter compared to $633 million in the same quarter a year ago,
representing approximately 47 percent and 43 percent of our total sales and
operating revenues for the third quarters of 2004 and 2003, respectively. The
increase in sales from marketing activities was primarily due to higher
international and domestic crude oil revenues resulting from higher crude oil
prices.
Nine Months Results: Earnings from continuing operations totaled $53 million in
the nine month period of 2004 compared to $49 million in the same period a year
ago. The higher 2004 results reflect gains from crude oil and natural gas
trading activities, which were positively impacted by volatile commodity prices.
This was partially offset by lower earnings from our pipelines business. The
nine month period of 2003 results included gains on the sale of domestic
pipeline assets.
The segment's sales and operating revenues were $3.08 billion in the nine month
period of 2004 compared to $2.7 billion in the same period a year ago. Included
in these totals were sales from marketing activities totaling $2.6 billion in
the current nine month period compared to $2.29 billion in the same period a
year ago, representing approximately 54 percent and 48 percent of our total
sales and operating revenues for the 2004 and 2003 periods, respectively. The
increase in sales from marketing activities was primarily due to higher
international and domestic crude oil revenues resulting from higher crude oil
prices, which was partially offset by lower domestic natural gas revenues
resulting from lower volumes attributable mainly to property sales in 2003.
-40-
Geothermal
The Geothermal segment includes geothermal steam production for power
generation, with operations in the Philippines and Indonesia. Geothermal
activities also include the operation of geothermal steam-fired power plants in
Indonesia and equity interests in gas-fired power plants in Thailand.
Third Quarter Results: Earnings from continuing operations totaled $3 million in
the current quarter compared to $19 million in the same period a year ago. The
current period was negatively impacted by lower earnings from our equity
interests in certain gas-fired power plants, which included an after-tax
impairment of $11 million and foreign exchange losses in the current quarter
compared to foreign exchange gains in the prior year quarter.
Nine Months Results: Earnings from continuing operations totaled $97 million in
the nine month period of 2004 compared to $38 million in the same period a year
ago. The 2004 results included a $46 million gain from the settlement of the
outstanding contract dispute in our Philippines operations (see "Philippines
Settlement" below for further detail) and a $21 million after-tax gain from the
sale of our rights and interests in the Sarulla geothermal project on the island
of Sumatra, Indonesia. The remaining increase was primarily due to improved
results from our operations at Gunung Salak. The prior year's results reflect
lost generation and additional repair costs associated with damage caused by
landslides at Gunung Salak. In addition, the nine months results in 2004 reflect
lower earnings from our equity interests in certain gas-fired plants as compared
to the same period a year ago, primarily due the aforementioned equity
investment impairment and foreign exchange losses in 2004 compared to foreign
exchange gains in 2003.
Philippines Settlement: Our Unocal Philippines, Inc. ("UPI"), formerly known as
Philippines Geothermal, Inc., subsidiary obtained in June 2004 final Philippine
government and court approvals of a settlement for past contractual issues
covering the ongoing operations of the steam resources at Tiwi and Mak-Ban on
the island of Luzon. In July, UPI received $50 million in cash and expects to
receive the outstanding settlement amount owed of $25 million by National Power
Corporation and Power Sector Assets and Liabilities Management Corporation by
the end of the year.
Corporate and Other
Corporate and Other includes general corporate overhead, miscellaneous
operations (including real estate, carbon and mineral businesses), other
corporate unallocated costs (including environmental and litigation expenses)
and net interest expense.
Third Quarter Results: The results for the current quarter were a loss of $18
million compared to a loss of $126 million in the same period a year ago. The
third quarter of 2004 results included a net tax benefit of $32 million relating
primarily to settlements and assessments with various taxing authorities. The
third quarter of 2004 included an after-tax gain of $16 million from the sale of
non-oil and gas property in Parachute, Colorado. After-tax expenses for
environmental and litigation matters for the current quarter were $21 million
compared to $38 million in the same period a year ago. In addition, the current
quarter reflected approximately $10 million after-tax in higher results from our
minerals business due to higher margins attributable to molybdenum prices and
$10 million after-tax in lower pension and retiree medical related expenses. The
third quarter of 2003 included a $6 million after-tax charge related to our 2003
restructuring plan.
Nine Months Results: The results for the nine month period of 2004 were a loss
of $195 million compared to a loss of $338 million in the same period a year
ago. After-tax expenses for environmental and litigation matters for the nine
months of 2004 were $57 million compared to $83 million after-tax for the same
period a year ago. The nine month period of 2004 included net tax benefits of
$60 million relating primarily to settlements and assessments with various
taxing authorities. The current year results included a provision of $46 million
pre-tax ($29 million after-tax) associated with the arbitration ruling regarding
Agrium's Kenai, Alaska nitrogen-based fertilizer plant, and our obligations to
supply natural gas to the plant. The nine month period of 2004 also included an
after-tax gain of $16 million from the sale of non-oil and gas property in
Parachute, Colorado. In addition, the nine month period reflected approximately
$10 million after-tax in higher results from our minerals business due to higher
margins attributable to molybdenum prices and $10 million after-tax in lower
pension and retiree medical related expenses due primarily to recognition in the
third quarter of 2004 of the federal subsidy provisions of the Medicare
Prescription Drug, Improvement and Modernization Act of 2003 and the impact of
our $100 million contribution to our qualified U.S. pension plan. The nine month
period
-41-
of 2004 included a $1 million after-tax benefit from the adjustment to the 2003
company-wide restructuring, for which we recorded charges totaling $23 million
in 2003.
LIQUIDITY AND CAPITAL RESOURCES
Cash and cash equivalents on hand totaled $780 million at September 30, 2004, up
from $404 million at the end of 2003. Based on current commodity prices and
current development projects, we expect cash generated from operating
activities, asset sales and cash on hand to be sufficient for the remainder of
2004 to cover our operating and capital spending requirements and to make
expected dividend payments and to pay down scheduled debt. In addition, we
believe that our available borrowing capacity is sufficient to enable us to meet
unanticipated cash requirements if needed. As of the date of this report, there
are no material restrictions imposed by credit agreements or other contracts to
which Unocal or its subsidiaries is a party that would restrict inter-company
loans, capital contributions, dividends or other distributions of cash among
Unocal and its consolidated subsidiaries, equity investees or variable interest
entities or otherwise have a material impact on our liquidity.
Cash Flows from Operating Activities
Cash flows from operating activities, including working capital and other
changes, were $1.69 billion for the nine month period ended September 30, 2004,
compared with $1.65 billion for the same period a year ago. The increase
principally reflected the effects of higher worldwide commodity prices. The
positive impact from higher prices was partially offset by the contribution of
$100 million to our U.S. Qualified Retirement Plan and the negative impact from
lower North America production, compared to the same period a year ago. The nine
month period of 2004 reflects higher tax payments net of refunds. Refunds
included the receipt of $35 million relating to a federal income tax refund for
the 2003 tax year and the receipt of payment from the Indonesian government in
settlement of disputed value added taxes we paid in prior years.
Asset Sales
Pre-tax proceeds from asset sales relating to continuing and discontinued
operations were $401 million for the nine month period ended September 30, 2004.
The current year included net proceeds of $176 million from the sale of certain
of our mineral fee lands in the U.S., $67 million from the sale of our 50
percent equity interest in a Brazilian exploration and production venture that
owned our remaining oil and natural gas assets in Brazil, $60 million from the
sale of our rights and interests in the Sarulla geothermal project in Indonesia
and $19 million from the sale of the Cal Ven Pipeline system in Canada. We also
received approximately another $31 million from the sale of various oil and gas
properties, primarily in the Gulf of Mexico and $48 million from the sale of
other miscellaneous and real estate properties including the sale of non-oil and
gas property in Parachute, Colorado.
Pre-tax proceeds from asset sales relating to continuing and discontinued
operations were $354 million for the nine month period ended September 30, 2003.
We received $122 million from the sale of most of our shares in Tom Brown Inc.
and $80 million from the sale of our equity interest in Matador. We also
completed the sale of various properties in Canada, onshore U.S. and the Gulf of
Mexico in the first half of 2003, which netted us approximately $118 million in
proceeds. In addition, cash proceeds included $23 million in other miscellaneous
property sales and $11 million related to a participation payment which was
received from the purchaser of our former West Coast refining, marketing and
transportation assets covering price differences between California Air
Resources Board Phase 2 gasoline and conventional gasoline.
Capital Expenditures and Other Investing Activities
Capital expenditures were $1.24 billion for the nine month period of 2004
compared with $1.3 billion in the same period a year ago. This year's
expenditures level primarily reflects lower exploratory capital requirements in
the Gulf of Mexico. Last year, capital expenditures in our Midstream and
Marketing segment included the BTC pipeline project expenditures prior to its
financing by the BTC Pipeline Company. In the nine month period of 2004, capital
expenditures included approximately $522 million for the development of
undeveloped proved oil and gas reserves, primarily in Indonesia, Azerbaijan,
Thailand and the deepwater Gulf of Mexico.
-42-
In the nine month period of 2004, cash flows from investing activities included
$48 million representing a return of capital from the completion of the BTC
financing which closed in February 2004. The BTC Pipeline Company is financing
up to 70 percent of the pipeline's cost. We have an 8.9 percent equity interest
in the pipeline company.
Long-term Debt
During the nine month period of 2004, we reduced our outstanding balance on the
6-1/4% convertible junior subordinated debentures by $269 million, retired $173
million in 6.375% notes and paid down $20 million of medium-term notes that
matured in 2004. In addition, we retired the remaining $24 million limited
recourse loan balance under the AIOC Early Oil Project in 2004. We also made a
$15 million principal payment on the variable rate portion of the Overseas
Private Investment Corporation Financing Agreement for the West Seno project in
Indonesia, which is scheduled to mature in June 2009.
These decreases were partially offset by $40 million in new borrowing relating
to Phase 1 development of the Azeri-Chirag-Gunashli structure in the Azerbaijan
sector of the Caspian Sea, scheduled for repayment semiannually from June 2006
through December 2015 and $95 million drawn under two new loans from the OPIC
Financing Agreement, both limited recourse loans, for the first phase of the
West Seno project in Indonesia. One loan was drawn for $50 million and the other
was drawn for $45 million, and they each carry fixed rates of 3.61% and 4.78%,
respectively. Principal payments on the $50 million loan are scheduled
semiannually from June 2005 to December 2007, and on the $45 million loan
payments are scheduled from June 2005 to June 2008.
Other Financing Activities
In August 2004, we repurchased 4,130,000 shares of our common stock at a cost of
approximately $150 million utilizing cash on hand. This repurchase program was
announced in July 2004 (see Item 2 of Part 2 for further detail).
Credit Facilities and Other Financing Sources
Revolving Credit Facility
General
In August 2004, our wholly owned subsidiary, Union Oil Company of
California, entered into a $1.0 billion revolving credit agreement with a
maturity date of August 12, 2009, and terminated its $600 million and $400
million credit facilities. Unocal guaranteed the obligations of Union Oil under
the credit agreement. The credit agreement provides for the lenders to make up
to $500 million of the $1.0 billion available in the form of letters of credit.
As of September 30, 2004, there were no borrowings outstanding under
the credit agreement. Our ability to borrow at any particular time under the
credit agreement is subject to the accuracy of certain representations and
warranties and the absence of any defaults or events of default that we believe
are customary for such a facility.
The following is a summary of certain provisions of our credit
agreement. It is not a complete discussion of all provisions or terms of the
credit agreement. Please refer to the complete agreement, which we have filed as
Exhibit 10 to our Form 8-K dated and filed August 18, 2004.
Interest Rates
The interest rate for any borrowing under the credit agreement is
determined at our option as follows:
o Eurodollar loans for specified periods at the applicable LIBO Rate
plus an applicable borrowing spread; or
o competitive bid loans provided by any or all of the lenders through
a competitive process; or
o a rate established each day as the greater of the prime rate or the
federal funds rate plus 1/2%.
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Credit Rating Triggers
The applicable rate for Eurodollar revolving loans and the applicable
facility fees vary in accordance with Unocal's credit ratings. Lower credit
ratings result in higher facility fees and Eurodollar loan rates and higher
credit ratings result in lower facility fees and Eurodollar loan rates. The
credit agreement does not have drawdown restrictions or prepayment obligations
in the event of a credit rating downgrade.
Mandatory Prepayments
The credit agreement provides for termination of the loan commitments
and mandatory prepayments of any borrowings, interest and fees under certain
specified events, including if (1) any person or group becomes the beneficial
owner of more than 30 percent of the then outstanding voting stock of Unocal
other than in a transaction having the approval of Unocal's board of directors,
at least a majority of which are continuing directors, or (2) if continuing
directors cease to constitute at least a majority of Unocal's board of
directors.
Negative Covenants
The credit agreement contains financial and other covenants, including
covenants that limit our and certain of our subsidiaries' abilities to, among
other things:
o incur liens upon any of our existing or future property or assets,
other than permitted liens allowed by the credit agreement; and
o exceed a total debt to total capitalization ratio of 0.70 to 1.0
(total capitalization is defined as total debt plus total equity,
with the convertible junior subordinated debentures excluded from
total debt and included as equity in the ratio calculation).
Events of Default
The credit agreement includes events of default relating to:
o failure to pay amounts due in accordance with the terms of the
credit agreement;
o failure to observe or perform any other affirmative covenants or
other agreements under the credit agreement that remains uncured
for thirty days after receipt of a notice of default;
o failure to observe or perform any negative covenants under the
credit agreement;
o accuracy of representations and warranties;
o defaults and accelerations of other material indebtedness or
material guarantee obligations;
o bankruptcy, insolvency, reorganization and other similar
proceedings and actions;
o certain ERISA matters;
o material non-payment or non-appeal of judgments and decrees;
o failure to own 100 percent of Union Oil or the majority of each
borrowing subsidiary; and
o unenforceability of any guarantees under the credit agreement.
The occurrence of an event of default may result in the termination of
the loan commitments and require prepayments of any borrowings, interest and
fees.
Canadian Credit Facility
We also have a $295 million Canadian dollar-denominated non-revolving
credit facility with a variable rate of interest due to terminate on December
19, 2005. At September 30, 2004, the borrowing under the Canadian credit
facility translated to $232 million, using the applicable foreign exchange rate.
-44-
Commercial Paper; Accounts Receivable Securitization; Universal Shelf
In addition to our revolving credit agreement, we have historically
relied on the commercial paper market and our accounts receivable securitization
program to cover near-term borrowing requirements. At September 30, 2004, we had
no outstanding balance under the commercial paper or accounts receivable
securitization programs. We also have in place a universal shelf registration
statement as of September 30, 2004, with an unutilized balance of approximately
$1.539 billion, which is available for the future issuance of other debt and/or
equity securities depending on our needs, market conditions and compliance with
our negative covenants under our credit agreement. From time to time, we may
also look to fund some of our long-term projects using other financing sources,
including multilateral and bilateral agencies.
Credit Ratings
Maintaining investment-grade credit ratings, that is "BBB- / Baa3" and above
from Standard & Poor's Ratings Services and Moody's Investors Service, Inc.,
respectively, is a significant factor in our ability to raise short-term and
long-term financing. As a result of our current investment grade ratings, we
have access to both the commercial paper and bank loan markets. We currently
have a BBB+ / Baa2 credit rating by Standard & Poor's and Moody's, respectively,
and an A-2 / Prime-2 for our commercial paper ratings. Moody's and Standard &
Poor's outlooks, as of the date of the filing of this report, remained stable
for our long term debt and commercial paper ratings. In the event that our
credit ratings were downgraded to below investment grade, our ability to access
additional short and long-term financing sources and the terms of any such
financing would be adversely impacted. However, based on current commodity
prices, we believe that cash generated from operating activities, asset sales
and cash on hand would be sufficient for the remainder of 2004 to cover our
operating and capital spending requirements for current development projects and
to make expected dividend payments and to pay down scheduled debt. We also
believe that our available borrowing capacity under our revolving credit
agreement would be sufficient to enable us to meet unanticipated cash
requirements if needed.
Off-Balance Sheet Arrangements
We have a construction completion guarantee related to debt financing associated
with our equity interest in the development of the BTC pipeline project. The
maximum potential future payments under the guarantee are estimated to be $310
million. Extending guarantees to creditors allows the project to reduce its
borrowing costs. We are not the primary beneficiary in this arrangement. See
note 17 to the consolidated financial statements for a detailed discussion.
-45-
ENVIRONMENTAL MATTERS
We are committed to operating our business in a manner that is environmentally
responsible. This commitment is fundamental to our core values. As part of this
commitment, we have procedures in place to audit and monitor our environmental
performance. In addition, we have implemented programs to identify and address
environmental risks throughout our company.
Probable costs associated with identified and reasonably estimable environmental
obligations have been accrued in a reserve for such obligations. Accruals are
based on developments to date, our estimates of the outcomes of these matters
and our experience in addressing these matters. As the scope of the liabilities
becomes better defined, there will be changes in the estimates of future costs,
which could have a material effect on our future results of operations,
financial condition or liquidity. At September 30, 2004, our reserves for
environmental remediation obligations totaled $252 million, of which $106
million was included in current liabilities. During the nine month period of
2004, cash payments of $63 million were applied against the reserves and $63
million was added to the reserves. We may also incur additional liabilities at
sites where remediation liabilities are probable but future environmental costs
are not presently reasonably estimable because the sites have not been assessed
or the assessments have not advanced to stages where costs are reasonably
estimable. At those sites where investigations or feasibility studies have
advanced to the stage of analyzing feasible alternative remedies and/or ranges
of costs, we estimate that we could incur possible additional remediation costs
aggregating approximately $225 million.
The reserve amounts and estimated possible additional costs are grouped into the
following four categories:
At September 30, 2004
---------------------------------
Estimated Possible
Millions of dollars Reserve Additional Costs
-------------------------------------------------------------------------------
Superfund and similar sites $ 15 $ 15
Active Company facilities 31 35
Company facilities sold with retained liabilities
and former Company-operated sites 97 80
Inactive or closed Company facilities 109 95
-------------------------------------------------------------------------------
Total $ 252 $ 225
===============================================================================
See notes 16 and 17 to the consolidated financial statements in Item 1 of this
report for additional information on environmental related matters.
During the nine month period of 2004, provisions of $42 million were recorded
for the "Company facilities sold with retained liabilities and former
Company-operated sites" category. These provisions were for approximately 225
sites where we had operated service stations, bulk plants or terminals. The
provisions were based on new and revised cost estimates that were developed for
these sites in the nine month period of 2004. The provisions were also for new
and revised cost estimates for the assessment and remediation of oil fields in
Michigan and California. We will perform assessments on certain areas within
these fields to determine if they have been contaminated by our former
operations. We have determined that other areas within these sites are
contaminated and will require remediation.
We recorded provisions of $9 million during the nine month period of 2004 for
the "Active Company facilities" category of sites. The provisions were primarily
for the estimated additional costs of the remedial investigation and feasibility
study (RI/FS) that is continuing at a molybdenum mine located in Questa, New
Mexico, which is owned by our Molycorp subsidiary. The estimated additional
costs are based on an evaluation that Molycorp performed in the second quarter
of 2004 of the remaining work that will be required to complete the RI/FS.
Molycorp has been conducting the RI/FS cooperatively with the U.S. Environmental
Protection Agency to determine what, if any, adverse impacts past mining
operations may have had on the environment.
The reserve related to sites in the "Inactive or closed Company facilities"
category was increased by $11 million during the nine month period of 2004. The
increase was primarily for our former refinery in Beaumont, Texas and a former
terminal in Edmonds, Washington. A provision was recorded for the updated cost
estimates to close impoundments used in the former operations at the Beaumont,
Texas site. In the first quarter of 2004, final design work and related
-46-
detailed cost estimates to close these impoundments were completed. We also
received final approval of a permit for these projects from the Texas Commission
on Environmental Quality. The reserve for this category of sites was also
increased for the estimated cost of cleanup work at a shutdown terminal in
Edmonds, Washington. The cost includes the implementation and operation of a
system to remediate petroleum hydrocarbon contamination caused by our former
petroleum products storage and transportation operation at the facility.
In the nine month period of 2004, estimated possible additional costs in excess
of amounts included in the reserves for remediation obligations increased by $20
million. Included is an increase of $10 million for sites in the "Inactive or
closed Company facilities" category. The increase is primarily for possible
additional remediation costs for a molybdenum processing facility in Washington,
Pennsylvania, which is owned by our Molycorp subsidiary. The remediation that
may be required is for tar-contaminated soil caused by the operations of the
former owner of the property.
Possible additional costs for the "Active Company facilities" category of sites
increased by $5 million in the first nine months of 2004. These costs are
primarily to close two impoundments and remove a pipeline at our Molycorp
subsidiary's lanthanide mine in California. Releases from the impoundments and
pipeline of wastewater and tailings generated by the mining and milling
operation had caused soil and groundwater contamination at the facility.
During the first nine months of 2004, possible additional costs for the "Company
facilities sold with retained liabilities and former Company-operated sites"
category increased by $5 million. The higher costs were primarily for a former
oil field in Michigan and for former service station sites at various locations.
Estimated possible additional costs for the former Michigan oil field were
increased for the cost of remediation that may need to be performed on certain
areas within the site that may have been contaminated by the former oil field
operation. These costs are based on an evaluation being performed at the site in
2004. Higher possible additional costs for the former service station sites are
based on new and revised estimates of the upper end of remediation costs ranges
that were developed during the nine month period of 2004.
-47-
OPERATIONS OUTLOOK
The following operations outlook is based upon our current expectations and
beliefs. These statements are subject to a number of known and unknown risks and
uncertainties that could cause actual results to differ materially from those
described. Please see the cautionary statement under "Forward-Looking
Statements" on page iii of this report. This outlook discusses our current
expectations regarding certain important operational activities for the
remainder of 2004 and for other future time periods. It is not intended to be a
complete discussion of all future operational activities.
We expect energy prices to remain volatile due to a variety of fundamental and
market perception factors including variability of the weather on a year-to-year
basis, worldwide demand, crude oil and natural gas inventory levels, production
quotas set by OPEC, current and future worldwide political instability,
worldwide security and other factors. We have secured fixed price "hedges" to
seek to mitigate some of that volatility, primarily relating to a portion of our
2004 and 2005 North America natural gas and crude oil production.
We believe the economic situation in Asia, where most of our international
activity is centered, is becoming more positive. We look at the natural gas
market in Asia as one of our major strategic investments.
Full-year 2004 production is expected to exceed 405,000 BOE per day. Our current
capital expenditures forecast for the full-year 2004 is between $1.7 and $1.8
billion, down from the $2.0 billion previously forecast. The primary reason for
the decrease is related to our decision to terminate our participation in five
contracts to explore for, develop and market natural gas resources in the Xihu
Trough off the coast of Shanghai, in the East China Sea and delays in certain
development projects in deepwater Indonesia.
Exploration and Production - North America
United States
o Two new deepwater Gulf of Mexico developments are moving toward completion
in 2004. The Mad Dog field (operated by BP p.l.c. ) is expected to come on
stream in the first quarter of 2005. The K-2 field (operated by Eni SpA.)
is expected to come on stream in the second quarter of 2005. The estimate
of initial net production is about 2,000 to 3,000 BOE/d from each field,
rising to 5,000 to 6,000 BOE/d by the end of 2005. We have a 15.6 percent
working interest in Mad Dog and a 12.5 percent working interest in K-2.
o Evaluation of the extensive well data collected from the St. Malo discovery
well and the Dana Point deepening appraisal well on Walker Ridge Block 678
continues. The evaluation will focus on productivity, additional appraisal
operations and the viability of development options. We have a 28.75
percent working interest in the St. Malo discovery.
o We are currently drilling a deeper zone test on the Sequoia prospect below
our Mirage discovery. Following Sequoia, we expect to drill the Southwest
Ridge appraisal well on the Mad Dog structure. Other deep water Gulf of
Mexico drilling activities expected include follow-up wells on our Puma
discovery and a deep test under the Mad Dog structure operated by BP. In
addition, we expect to participate in a Miocene test on the Chilkoot
prospect in Green Canyon Block 320, operated by Kerr McGee Corporation.
o In Alaska, first production from our Happy Valley discovery is expected to
begin in November 2004. Exploratory drilling and evaluation is currently in
progress at some prospects in the southern Kenai Peninsula with other
natural gas prospects in the same area targeted for exploration.
Exploration and Production - International
Asia
Thailand:
o Thailand's electricity market continues to grow at approximately 8 percent
per annum. Additional supplies of natural gas to meet that growth have been
constrained by pipeline capacity. Recent de-bottlenecking activities on
-48-
the two existing pipelines in the Gulf of Thailand should allow us an
opportunity for increased production in 2004 and 2005, prior to the
expected completion of the third pipeline in 2006.
o Phase 2 development of the Thailand oil project is now underway. Start up
is expected late in the second quarter of 2005. This project is expected to
add 10,000 BOE/d net when full capacity is achieved in late third quarter
of 2005.
o We anticipate signing final agreements in 2005 to extend our existing
natural gas sales agreements and expand contract quantities by 15 percent
by 2006, and another 50 percent by 2010-2012.
o The Arthit field's natural gas sales agreement has been signed and
development work has begun with first production anticipated in late 2006
or early 2007.
Indonesia:
o At the end of the third quarter there were 24 wells completed in the West
Seno field. Gross production averaged 26,000 BOE/d during the third quarter
of 2004. We expect to complete Phase 1 drilling activities by the end of
2004 with a total of 28 wells. The 2004 gross exit rate for the field is
expected to average between 35,000 and 45,000 BOE/d. Bids were opened for
fabrication and installation of a tension leg platform and infield
pipelines for Phase 2 of the West Seno field development. The bid results
were unacceptably high. Currently, evaluation of extended reach drilling
from the existing Phase 1 platform is being considered as a means to more
cost effectively recover the resource in the southern portion of the field;
however, potential production from any Phase 2 development will be after
2005.
o We are continuing to work on solidifying our development plans for our
deepwater natural gas projects. Development will likely be around two major
hubs. First production is expected in late 2007 from the Gendalo field
where we have begun front-end engineering and design work. The second
development project is expected to be the Gehem-Ranggas oil and gas complex
where 10 appraisal wells have been drilled to date and where first
production is expected to come on-line by 2010-2011.
o We expect exploration and appraisal drilling to continue in 2004 in the
deep water Kutei Basin. This drilling activity will test new prospects in
recently awarded PSCs in the deep water.
Vietnam:
o In early 2004, we signed a Heads of Agreement with PetroVietnam for natural
gas development. We fulfilled our drilling commitments in the second
quarter of 2004, but agreed to drill two additional wells on one block to
retain additional acreage. Work continues to bring Vietnam gas to market
between 2008 and 2010.
Bangladesh:
o Facility construction and development drilling on the Moulavi Bazar field
is progressing. First production from Moulavi Bazar is expected late in the
first quarter or early in the second quarter of 2005. The new field is
expected to increase production in Bangladesh by 15,000 BOE/d when
production begins and increase to 25,000 BOE/d by the end of 2005.
o We received approval for a plan of development for the Bibiyana field in
second quarter of 2004 and negotiations with Petrobangla continue on a gas
purchase and sales agreement. We anticipate that the gas purchase and sales
agreement will be finalized in the fourth quarter of 2004. The Bibiyana
field is capable of being developed in stages, which could provide
Bangladesh with natural gas resources in the short, medium and long-term
time frames. We expect first production by the end of 2006.
-49-
Other International
Australia:
o In the fourth quarter of 2004, we plan to participate in drilling a
deepwater well on Block VIC/P52, which is located in the Otway Basin,
offshore Victoria. We hold a 33.33-percent non-operating working interest
in the block.
Azerbaijan:
o Progress continues in 2004 on the development of the BP operated AIOC
project. Gross production is expected to ramp up to more than 200 MBbl/d
in 2005, rising to 700 MBbl/d in 2007 and over 1 million Bbl/d by 2009.
We have a 10.28 percent working interest. In 2005, we expect Phase 1
development to commence in the second quarter of 2005. The initial average
net production rate is expected to be approximately 6,000 BOE/d for the
first three months, climbing to 12,000 BOE/d in the next three months and
to 18,000 BOE/d in the subsequent three months.
Midstream and Marketing
In parallel with the AIOC field development work in Azerbaijan, the BTC pipeline
is expected to be fully operational in the second half of 2005. The portions of
the pipeline through Azerbaijan and Georgia are expected to be complete and
ready for line-fill in the second quarter of 2005. The BTC pipeline will
transport the crude oil from the AIOC field to the Turkish port of Ceyhan and
will have a capacity of 1 million Bbl/d. Our interest in this pipeline is 8.9
percent.
Corporate and Other
On July 29, 2004, we made a voluntary pre-tax contribution of $100 million to
our U.S. Qualified Retirement Plan. In addition, we expect that mandated
employer contributions to the plan will not be payable until 2009. However, less
than expected future returns on plan assets or a decrease in the discount rate
could accelerate the requirement to make cash contributions to the plan before
2009.
On October 15, 2004, we amended the Unocal Medical Plan to set a maximum amount
to our contributions for retiree medical coverage. As a result of this revision,
we were required to remeasure our postretirement benefit obligation as of
October 15, 2004. This calculation resulted in a net reduction of $73 million to
our accumulated postretirement benefit obligation and is estimated to decrease
our future annual pre-tax postretirement expense by $12 million.
In October 2004, our Molycorp subsidiary sold down its interest of its equity
investment in Companhia Brasileira de Metalurgia e Mineracao, a niobium
operation in Brazil, from 44.59 percent to 40 percent for $27 million.
FUTURE ACCOUNTING CHANGES
See note 2 to the consolidated financial statements for information about recent
accounting pronouncements.
Additionally, the American Jobs Creation Act of 2004 (the "Act") was signed into
law by the U.S. President on October 22, 2004. The Act contains numerous changes
to U.S. tax law, both temporary and permanent in nature, including a potential
tax deduction with respect to certain qualified domestic manufacturing
activities, changes in the carryback and carryforward utilization periods for
foreign tax credits and a dividend received deduction with respect to
accumulated income earned abroad. The new law could potentially have an impact
on our effective tax rate, future taxable income and cash and tax planning
strategies, amongst other affects. We are currently in the process of evaluating
the impact that the Act will have on our financial position and results of
operations.
-50-
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
We are exposed to market risks, which may give rise to losses from adverse
changes in market prices and rates. The primary market risks to which we are
exposed are: (1) commodity prices, (2) interest rates and (3) foreign currency
exchange rates.
Market risk generally represents the risk that losses may occur in the values of
financial instruments as a result of changes in commodity prices, interest rates
and foreign currency exchange rates . As part of our overall risk management
strategies, we use derivative financial instruments to manage and seek to reduce
risks associated with these factors. We also trade hydrocarbon derivative
instruments, such as futures contracts, swaps and options, to exploit
anticipated opportunities arising from commodity price fluctuations. To the
extent that we engage in hedging activities to seek to protect ourselves from
commodity price volatility, we may be prevented from realizing the benefits of
price increases above the levels of the hedges. In addition, speculative trading
in hydrocarbon commodities and derivative instruments in connection with our
risk management activities subjects us to additional risk.
We determine the fair values of our derivative financial instruments primarily
based upon market quotes of exchange traded instruments. Most futures and
options contracts are valued based upon direct exchange quotes or industry
published price indices. Some instruments with longer maturity periods require
financial modeling to accommodate calculations beyond the horizons of available
exchange quotes. These models calculate values for outer periods using current
exchange quotes (i.e., forward curve) and assumptions regarding interest rates,
commodity and interest rate volatility and, in some cases, foreign currency
exchange rates. While we feel that current exchange quotes and assumptions
regarding interest rates and volatilities are appropriate factors to measure the
fair value of our longer termed derivative instruments, other pricing
assumptions or methodologies may lead to materially different results in some
instances.
Commodity Price Risk - We are a producer, purchaser, marketer and trader of
certain hydrocarbon commodities such as crude oil and condensate, natural gas
and refined products and are subject to the associated price risks. We use
hydrocarbon price-sensitive derivative instruments ("hydrocarbon derivatives"),
such as futures contracts, swaps, collars and options, to mitigate our overall
exposure to fluctuations in hydrocarbon commodity prices. We may also enter into
hydrocarbon derivatives to hedge contractual delivery commitments and future
crude oil and natural gas production against price exposure. We also actively
trade hydrocarbon derivatives, primarily exchange regulated futures and options
contracts, subject to internal policy limitations.
We use a variance-covariance value at risk model to assess the market risk of
our hydrocarbon derivatives. Value at risk represents the potential loss in fair
value we would experience on our hydrocarbon derivatives, using calculated
volatilities and correlations over a specified time period with a given
confidence level. Our risk model is based upon current market data and uses a
three-day time interval with a 97.5 percent confidence level. The model includes
offsetting physical positions for any existing hydrocarbon derivatives related
to our fixed price pre-paid crude oil and pre-paid natural gas sales. The model
also includes our net interests in our subsidiaries' crude oil and natural gas
hydrocarbon derivatives and forward sales contracts. Based upon our risk model,
the value at risk related to hydrocarbon derivatives held for hedging purposes
was approximately $35 million at September 30, 2004. The value at risk related
to hydrocarbon derivatives held for non-hedging purposes was approximately $3
million at September 30, 2004.
See "Hydrocarbon Derivatives Tables."
Interest Rate Risk - From time to time, we temporarily invest our excess cash in
short-term interest-bearing securities issued by high-quality issuers. Our
policies limit the amount of investment in securities of any one financial
institution. Due to the short time the investments are outstanding and their
general liquidity, these instruments are classified as cash equivalents in the
consolidated balance sheet and do not represent a material interest rate risk to
us. Our primary market risk exposure to changes in interest rates relates to our
long-term debt obligations. We manage our exposure to changing interest rates
principally with a combination of fixed and floating rate debt. Interest rate
risk sensitive derivative financial instruments, such as swaps or options, may
also be used depending upon market conditions.
We evaluated the potential effect that near term changes in interest rates would
have had on the fair value of our interest rate risk sensitive financial
instruments at September 30, 2004. Assuming a ten percent decrease in our
weighted average borrowing costs at September 30, 2004, the potential increase
in the fair value of our debt obligations and
-51-
associated interest rate derivative instruments, including the debt obligations
and associated interest rate derivative instruments of our subsidiaries, would
have been approximately $75 million at September 30, 2004.
Foreign Exchange Rate Risk - We conduct business in various parts of the world
and in various foreign currencies. To limit our foreign currency exchange rate
risk related to operating income, foreign sales agreements generally contain
price provisions designed to insulate our sales revenues against adverse foreign
currency exchange rates. In most countries, energy products are valued and sold
in U.S. dollars and foreign currency operating cost exposures have not been
significant. In other countries, we are paid for product deliveries in local
currencies but at prices indexed to the U.S. dollar. These funds, less amounts
retained for operating costs, are converted to U.S. dollars as soon as
practicable. Our Canadian subsidiaries are paid in Canadian dollars for their
crude oil and natural gas sales and have outstanding Canadian-dollar denominated
debt.
From time to time, we may purchase foreign currency options or enter into
foreign currency swap or foreign currency forward contracts to limit the
exposure related to our foreign currency debt or other obligations. At September
30, 2004, we had various foreign currency forward contracts outstanding related
to operations in Thailand and the Netherlands. We evaluated the effect that near
term changes in foreign exchange rates would have had on the fair value of our
combined foreign currency position related to our outstanding foreign currency
swaps, forward contracts and foreign-currency denominated debt. Assuming an
adverse change of ten percent in foreign exchange rates at September 30, 2004,
the potential decrease in fair value of the foreign currency swaps, foreign
currency forward contracts and foreign-currency denominated debt for us would
have been approximately $13 million at September 30, 2004.
Hydrocarbon Derivatives Tables - The following tables set forth the future
volumes and price ranges of hydrocarbon derivatives we held at September 30,
2004, along with the fair values of those instruments.
-52-
Open Hydrocarbon Hedging Derivative Instruments (a)
(Thousands of dollars)
Fair Value Asset
2004 2005 2006 2007-2008 (Liability) (b)(c)
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Futures Positions
Volume (MMBtu) 190,000 120,000 - - $ 486
Average price, per MMBtu $ 5.67 $ 6.10
Volume (MMBtu) (1,660,000) (14,640,000) - - $ (10,748)
Average price, per MMBtu $ 6.50 $ 6.98
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Swap Positions
Pay fixed price
Volume (MMBtu) 4,203,000 14,068,000 8,568,000 14,459,000 $ 128,317
Average swap price, per MMBtu $ 3.93 $ 3.99 $ 3.05 $ 2.50
Receive fixed price
Volume (MMBtu) 14,190,000 13,215,000 - - $ (26,040)
Average swap price, per MMBtu $ 5.84 $ 6.29
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Basis Swap Positions
Volume (MMBtu) 455,000 - - - $ 195
Average price received, per MMBtu $ 6.58
Average price paid, per MMBtu $ 6.41
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Futures Positions
Volume (Bbls) (2,000,000) (400,000) - - $ (22,602)
Average price, per Bbl $ 42.63 $ 41.42
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Collar Positions
Volume (Bbls) 180,000 - - - $ (4,985)
Average ceiling price, per Bbl $ 28.40
Average floor price, per Bbl $ 24.00
====================================================================================================================================
(a) Futures positions reflect long (short) volumes.
(b) Net claims against counterparties with non-investment grade credit ratings are immaterial.
(c) Includes $481 thousand in assumed liabilities which were capitalized as acquisition costs.
-53-
Open Hydrocarbon Non-Hedging Derivative Instruments (a)
(Thousands of dollars)
Fair Value Asset
2004 2005 2006 (Liability) (b)
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Futures Positions
Volume (MMBtu) 5,500,000 1,540,000 - $ 9,429
Average price, per MMBtu $ 5.99 $ 7.00
Volume (MMBtu) (720,000) (1,540,000) - $ (6,674)
Average price, per MMBtu $ 5.37 $ 7.15
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Swap Positions
Pay fixed price
Volume (MMBtu) 1,815,000 1,400,000 - $ 7,377
Average swap price, per MMBtu $ 6.30 $ 5.92
Receive fixed price
Volume (MMBtu) 1,590,000 1,400,000 - $ (8,034)
Average swap price, per MMBtu $ 6.05 $ 5.90
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Basis Spread Swap Positions
Volume (MMBtu) 9,455,000 39,930,000 4,525,000 $ (6,176)
Average price paid, per MMBtu $ 0.83 $ 0.57 $ 0.55
Volume (MMBtu) 9,760,000 39,930,000 4,525,000 $ 6,348
Average price received, per MMBtu $ 0.83 $ 0.57 $ 0.56
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Option (Listed & OTC)
Call Volume -Buy-(MMBtu) 1,250,000 - - $ (100)
Average Call price $ 7.00
Call Volume -Sell-(MMBtu) 14,150,000 500,000 - $ (5,721)
Average Call price $ 6.84 $ 9.00
Put Volume -Buy-(MMBtu) - - - $ -
Average Put Price $ -
Put Volume -Sell-(MMBtu) 1,200,000 2,000,000 - $ 354
Average Put Price $ 5.15 $ 4.50
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Spread Option (Over the Counter)
NYMEX / IFERC (c)
Call Volume (MMBtu) - - -
Average Strike price
Put Volume (MMBtu) - 1,000,000 - $ 36
Average Strike price $ 0.50
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Futures Positions
Volume (Bbls) 5,344,000 1,275,000 - $ 60,220
Average price, per Bbl $ 43.38 $ 40.62
Volume (Bbls) (5,104,000) (1,375,000) - $ (57,516)
Average price, per Bbl $ 43.65 $ 38.89
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Option (Listed & OTC)
Call Volumes -Buy-(Bbls) - - - $ (167)
Average price, per Bbl $ -
Call Volumes -Sell-(Bbls) 500,000 400,000 - $ (729)
Average price, per Bbl $ 50.20 $ 55.00
Put Volume -Buy-(Bbls) 300,000 - - $ 67
Average price, per Bbl $ 44.67
Put Volume -Sell-(Bbls) 580,000 - - $ 269
Average price, per Bbl $ 37.58
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Swap Positions
Pay fixed price
Volume (Bbls) 4,223,350 3,020,470 88,640 $ 91,639
Average swap price, per Bbl $ 44.78 $ 43.28 $ 39.76
Receive fixed price
Volume (Bbls) 4,318,820 2,847,720 315,920 $ (92,558)
Average swap price, per Bbl $ 43.33 $ 43.21 $ 39.76
====================================================================================================================================
(a) Futures positions reflect long (short) volumes.
(b) Includes $1,075 thousand net claims against counterparties with non-investment grade credit ratings.
(c) Prices quoted from the New York Mercantile Exchange (NYMEX) and Inside FERC Gas Report (IFERC).
-54-
ITEM 4. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to
ensure that information required to be disclosed in our reports under the
Securities Exchange Act of 1934 is processed, recorded, summarized and reported
within the time periods specified in the SEC's rules and forms and that such
information is accumulated and communicated to our management, including our
Chief Executive Officer and Chief Financial Officer, as appropriate, to allow
for timely decisions regarding required disclosure. In designing and evaluating
the disclosure controls and procedures, management recognizes that any controls
and procedures, no matter how well designed and operated, can provide only
reasonable assurance of achieving the desired control objectives, and management
is required to apply its judgment in evaluating the cost-benefit relationship of
possible controls and procedures.
As required by SEC Rule 13a-15(b), we carried out an evaluation, under
the supervision and with the participation of our management, including our
Chief Executive Officer and our Chief Financial Officer, of the effectiveness of
the design and operation of our disclosure controls and procedures as of the end
of the quarter covered by this report. Based on the foregoing, our Chief
Executive Officer and Chief Financial Officer concluded, as of that time, that
our disclosure controls and procedures were effective.
Internal Controls
Section 404 of the Sarbanes-Oxley Act of 2002 and related SEC rules
thereunder will require us to include an internal control report with our 2004
Annual Report on Form 10-K. The internal control report must assert, among other
things, (i) management's responsibilities to establish and maintain adequate
internal control over financial reporting and (ii) management's assessment of
the effectiveness of this internal control as of the end of the most recent
fiscal year. Our independent registered public accounting firm will be required
to audit, and report on, these assertions. Our management has formed a steering
committee and adopted a detailed project work plan to assess the adequacy of our
internal controls, remediate any control weaknesses that may be identified and
validate through testing that controls are functioning as documented. There was
no change in our internal control over financial reporting that occurred during
the three months ended September 30, 2004 that has materially affected, or is
reasonably likely to materially affect, our internal control over financial
reporting. We may make changes in our internal control processes from time to
time in the future.
-55-
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.
See the information with respect to certain legal proceedings pending or
threatened against Unocal previously reported in Item 3 of our Annual Report on
Form 10-K for the year ended December 31, 2003, as amended, and in Item 1 of
Part II of our Quarterly Report on Form 10-Q for the quarterly periods ended
March 31 and June 30, 2004. The following is incorporated by reference: the
information regarding the environmental remediation reserve and possible
additional remediation costs in notes 16 and 17 to the consolidated financial
statements in Item 1 of Part I of this report; the discussion of such amounts in
the Environmental Matters section of Management's Discussion and Analysis in
Item 2 of Part I; and the information regarding certain litigation and claims,
tax matters and other contingent liabilities in note 17 to the consolidated
financial statements in Item I of Part I of this report.
Information with respect to recent development in certain previously reported
proceedings is set forth below:
In the California Superior Court cases (the Doe and Roe cases) alleging
Unocal's liability in connection with the construction of the natural gas
pipeline from the Yadana field across Myanmar to the Thailand border,
described in Paragraph 3 of Item 3 of the 2003 Form 10-K, the court denied
a motion to dismiss and ruled that those claims related to liability (Phase
II) may proceed to trial. This recent ruling does not alter the court's
Phase I ruling that Unocal's foreign subsidiaries are not "alter egos" of
Unocal and Union Oil.
The state court ruling does not affect a separate case against Unocal
pending in the federal courts. The federal case is currently under review
by an en banc panel of the Ninth Circuit Court of Appeals in San Francisco,
California.
We believe that the outcomes of the federal and state cases are not likely
to have a material adverse effect on our financial condition or liquidity
or, based on current assessment of the cases, our results of operations.
Trial has been set for June 21, 2005.
-56-
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.
In the third quarter of 2004, 358,100 shares of our common stock, together with
cash in lieu of fractional shares, were issued upon conversion of 304,823 of the
6-1/4% trust convertible preferred securities of Unocal Capital Trust. The
shares of common stock were not registered under the Securities Act of 1933, as
amended (the "1933 Act"), in reliance upon the exemption from registration
afforded by Section 3(a)(9) of the 1933 Act, together with interpretations
thereof by the staff of the Division of Corporation Finance of the SEC, for a
security exchanged by the issuer with its existing security holders, of those of
a subsidiary where no commission or other remuneration is paid or given directly
or indirectly for soliciting such exchange.
The following table shows information regarding repurchases we made of our
shares of common stock during the third quarter of 2004:
----------------------------------------------------------------------------------------------------------------------------
Total Number of
Shares
Total Purchased as
Number of Part of Publicly Maximum Dollar Value of
Shares Average Announced Shares That May Yet Be
Purchased Price Paid Plans or Purchased Under the
Period (1) per share Programs Plans or Progrmas (2)(3)
----------------------------------------------------------------------------------------------------------------------------
July 1 through July 31, 2004 41,528 $37.46 None $189,000,000
----------------------------------------------------------------------------------------------------------------------------
August 1 through August 31, 2004 4,157,008 $36.28 4,130,000 $39,178,102
----------------------------------------------------------------------------------------------------------------------------
September 1 through September 30, 2004 25,382 $39.69 None $39,178,102
----------------------------------------------------------------------------------------------------------------------------
Total 4,223,918 $36.31 4,130,000 $39,178,102
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1. During the third quarter, we cancelled 15,878 shares repurchased for the
payment of withholding taxes due on restricted stock that vested under
various employee restricted stock plans.
During the third quarter, we purchased 78,108 shares in the open market and
distributed these shares to employee participants in Unocal's savings
plans, which are defined contribution plans with 401(k) features.
2. In December 1996, our board of directors authorized the repurchase of $400
million of our common stock. In January 1998, our board extended the stock
repurchase program, increasing the authorized amount by $200 million. There
is no expiration date to the repurchase program. At the beginning of the
third quarter of 2004, we had a balance of $189 million remaining for
additional repurchases. In August 2004, we purchased approximately $150
million of our common stock under this program, resulting in a balance of
approximately $39 million for additional purchases.
3. In October 2004, our board of directors authorized the repurchase from time
to time of shares of our common stock in order to offset the number of
shares of common stock issued or delivered by us upon the exercise or
granting, as the case may be, of existing or subsequently issued stock
options or shares of our restricted common stock. There is no expiration
date to the repurchase program. The board authorized management to
determine whether, and when, to effect any repurchases under this program
and did not limit the aggregate dollar amount for any such repurchases.
ITEM 6. EXHIBITS.
The Exhibit Index on page 58 of this report lists the exhibits that are filed or
furnished, as applicable, as part of this report.
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SIGNATURE
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 thereunto duly authorized.
UNOCAL CORPORATION
(Registrant)
Dated: November 4, 2004 By: /s/JOE D. CECIL
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Joe D. Cecil
Vice President and Comptroller
(Duly Authorized Officer and
Principal Accounting Officer)
EXHIBIT INDEX
3. Bylaws of Unocal, as amended through September 1, 2004 and currently in
effect (incorporated by reference to Exhibit 3.ii to Unocal's Current
Report on Form 8-K dated and filed September 1, 2004, File No. 1-8483).
10. Five-Year Credit Agreement, dated as of August 12, 2004, among Union
Oil Company of California and the borrowing subsidiaries from time to
time party thereto, as Borrowers; Unocal Corporation, as Guarantor;
JPMorgan Chase Bank, as Administrative Agent and Issuing Bank, Citicorp
USA, Inc., as Syndication Agent, and the lenders from time to time
party thereto (incorporated by reference to Exhibit 10 to Unocal's
Current Report on Form 8-K dated August 12, 2004, and filed August 18,
2004, File No. 1-8483).
12.1 Statement regarding computation of ratio of earnings to fixed charges
of Unocal Corporation for the nine months ended September 30, 2004 and
2003.
12.2 Statement regarding computation of ratio of earnings to fixed charges
of Union Oil Company of California for the nine months ended
September 30, 2004 and 2003.
31.1 Chief Executive Officer certifications pursuant to Exchange Act Rule
13a-14(a).
31.2 Chief Financial Officer certifications pursuant to Exchange Act Rule
13a-14(a).
32 Furnished Certifications Pursuant to Exchange Act Rule 13a-14(b).
Copies of exhibits will be furnished upon request. Requests should be addressed
to the Corporate Secretary and mailed to the address set forth on the cover page
to this report.
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