UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 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
-------------- -------------------
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 Act). Yes X No
------- -------
Number of shares of Common Stock, $1.00 par value, outstanding as of
July 30, 2004: 264,748,504
TABLE OF CONTENTS
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....................... 32
Item 3. Quantative and Qualitative Disclosures About Market Risk............ 46
Item 4. Controls and Procedures............................................. 50
PART II OTHER INFORMATION
Item 1. Legal Proceedings................................................... 51
Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases
of Equity Securities................................................ 51
Item 4. Submission of Matters to a Vote of Security Holders................. 52
Item 5. Other Information................................................... 52
Item 6. Exhibits and Reports on Form 8-K.................................... 53
SIGNATURE................................................................... 53
EXHIBIT INDEX............................................................... 54
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.
-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 and timing,
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 the use of cash on hand to repurchase common stock, preferred securities of
Unocal Capital Trust and to make a contribution to our U.S. Qualified
Retirement Plan,
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 and under guarantees and indemnities,
o economic conditions, and
o the impact of new or existing accounting pronouncements.
Although these statements are based upon Unocal's 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 changes in commodity prices and the effectiveness of our hedging activities
to manage that volatility,
o our ability to find or acquire additional oil and gas reserves and to
develop deepwater fields and other large projects in a timely and
cost-effective manner,
o the accuracy of our estimates and judgments regarding hydrocarbon resources
and formations,
o decline rates of producing properties in which we have an interest,
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 postemployment benefit plans and medical plans,
o the extent of our cash flow and other capital resources available to fund
capital expenditures,
o market conditions for our common stock and the preferred securities of
Unocal Capital Trust,
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 our ability to enter into agreements and transactions on acceptable terms
with, and performance by, foreign governmental entities, joint venture
partners, independent contractors, operators of properties in which we have
an interest and other third parties, 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 in their entirety by
this cautionary statement.
-------------------------------------
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.
-iii-
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CONSOLIDATED EARNINGS (UNAUDITED) UNOCAL CORPORATION
For the Three Months For the Six Months
Ended June 30, Ended June 30,
------------------------------------------------
Millions of dollars except per share amounts 2004 2003 2004 2003
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Revenues
Sales and operating revenues $ 1,921 $ 1,557 $ 3,751 $ 3,325
Interest, dividends and miscellaneous income 19 9 30 20
Gain on sales of assets 40 47 84 50
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Total revenues 1,980 1,613 3,865 3,395
Costs and other deductions
Crude oil, natural gas and product purchases 766 536 1,516 1,182
Operating expense 376 325 662 618
Administrative and general expense 46 87 109 138
Depreciation, depletion and amortization 240 254 472 513
Impairments 9 3 14 3
Dry hole costs 40 10 65 81
Exploration expense 48 88 98 143
Interest expense 46 36 87 74
Property and other operating taxes 22 21 42 43
Distributions on convertible preferred securities of subsidiary trust - 8 - 16
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Total costs and other deductions 1,593 1,368 3,065 2,811
Earnings from equity investments 38 53 75 96
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Earnings from continuing operations before
income taxes and minority interests 425 298 875 680
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Income taxes 144 131 323 297
Minority interests (1) 2 4 4
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Earnings from continuing operations 282 165 548 379
Earnings from discontinued operations (a) 59 12 62 15
Cumulative effect of accounting changes (b) - - - (83)
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Net earnings $ 341 $ 177 $ 610 $ 311
==================================================================================================================
Basic earnings per share of common stock (c)
Continuing operations $ 1.07 $ 0.65 $ 2.08 $ 1.47
Discontinued operations 0.22 0.04 0.24 0.06
Cumulative effect of accounting changes - - - (0.32)
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Net earnings $ 1.29 $ 0.69 $ 2.32 $ 1.21
==================================================================================================================
Diluted earnings per share of common stock (d)
Continuing operations $ 1.04 $ 0.64 $ 2.03 $ 1.45
Discontinued operations 0.21 0.04 0.22 0.05
Cumulative effect of accounting changes - - - (0.30)
------------------------------------------------------------------------------------------------------------------
Net earnings $ 1.25 $ 0.68 $ 2.25 $ 1.20
==================================================================================================================
Cash dividends declared per share of common stock $ 0.20 $ 0.20 $ 0.40 $ 0.40
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(a) Net of tax (benefit) $ 30 $ 7 $ 32 $ 9
(b) Net of tax (benefit) $ - $ - $ - $ (48)
(c) Basic weighted average shares outstanding (in thousands) 263,916 258,202 262,945 258,103
(d) Diluted weighted average shares outstanding (in thousands) 277,754 272,108 277,232 271,907
See Notes to the Consolidated Financial Statements.
-1-
CONSOLIDATED BALANCE SHEETS UNOCAL CORPORATION
At June 30, At December 31,
-------------------------------------
Millions of dollars 2004 (a) 2003
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Assets
Current assets
Cash and cash equivalents $ 939 $ 404
Accounts and notes receivable - net 1,316 1,292
Inventories 142 141
Deferred income taxes 108 119
Other current assets 37 35
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Total current assets 2,542 1,991
Investments and long-term receivables - net 886 892
Properties - net (b) 8,440 8,324
Goodwill 130 131
Deferred income taxes 314 300
Other assets 165 160
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Total assets $ 12,477 $ 11,798
===============================================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ 1,148 $ 1,072
Taxes payable 300 326
Dividends payable 53 52
Interest payable 42 43
Current portion of environmental liabilities 117 118
Current portion of long-term debt and capital leases 236 248
Other current liabilities 206 226
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Total current liabilities 2,102 2,085
Long-term debt and capital leases 3,104 2,635
Deferred income taxes 724 704
Accrued abandonment, restoration and environmental liabilities 871 844
Other deferred credits and liabilities 1,042 960
Minority interests 46 39
Commitments and contingencies - Note 16
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)) 276 271
Capital in excess of par value 1,154 1,031
Unearned portion of restricted stock issued (28) (13)
Retained earnings 3,961 3,456
Accumulated other comprehensive income (340) (298)
Notes receivable - key employees (4) (27)
Treasury stock - at cost (d) (431) (411)
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Total stockholders' equity 4,588 4,009
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Total liabilities and stockholders' equity $ 12,477 $ 11,798
===============================================================================================================
(a) Unaudited
(b) Net of accumulated depreciation, depletion and amortization of: $ 12,109 $ 11,711
(c) Number of shares outstanding (in thousands) 264,600 260,594
(d) Number of shares (in thousands) 11,162 10,623
See Notes to the Consolidated Financial Statements.
-2-
CONSOLIDATED CASH FLOWS (UNAUDITED) UNOCAL CORPORATION
For the Six Months
Ended June 30,
------------------------------
Millions of dollars 2004 2003
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Cash Flows from Operating Activities
Net earnings $ 610 $ 311
Adjustments to reconcile net earnings to
net cash provided by operating activities
Depreciation, depletion and amortization 472 515
Impairments 14 3
Dry hole costs 65 81
Amortization of exploratory leasehold costs 32 71
Deferred income taxes ( 6) 40
Gain on sales of assets (84) (50)
Gain on disposal of discontinued operations (84) (13)
Pension expense net of contributions 44 42
Restructuring provisions net of payments (14) 27
Cumulative effect of accounting changes - 83
Other (37) 4
Working capital and other changes related to operations
Accounts and notes receivable 45 6
Inventories (1) (4)
Accounts payable 76 26
Taxes payable (26) (3)
Other 20 (54)
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Net cash provided by operating activities 1,126 1,085
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Cash Flows from Investing Activities
Capital expenditures (includes dry hole costs) (801) (917)
Proceeds from sales of assets 158 191
Proceeds from sales of discontinued operations 120 -
Return of capital from affiliate company 48 -
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Net cash used in investing activities (475) (726)
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Cash Flows from Financing Activities
Long-term borrowings 135 79
Reduction of long-term debt and capital lease obligations (241) (143)
Minority interests (1) (3)
Repurchases of common stock (20) -
Proceeds from issuance of common stock 94 10
Dividends paid on common stock (105) (103)
Loans to key employees 24 3
Other (2) (7)
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Net cash used in financing activities (116) (164)
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Net increase in cash and cash equivalents 535 195
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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 $ 939 $ 363
===============================================================================================================
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized) $ 87 $ 83
Income taxes (net of refunds) $ 317 $ 275
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 six months ended June 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 20 - 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 ("VIE") 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 14 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.
Other Matters: In July 2004, the FASB issued for comment by August 17, 2004,
proposed FASB Staff Position No. 142-b, "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.
Unocal's net properties include approximately $1.43 billion and $1.53 billion at
June 30, 2004 and December 31, 2003, respectively, for investment in these
rights. Earlier, the FASB's Emerging Issues Task Force ("EITF") had given
consideration to whether these rights are intangible assets and subject to the
classification and disclosure provisions of FASB Statement No. 142.
-4-
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. Final detailed regulations specifying the manner in which actuarial
equivalency must be determined and the evidence required to demonstrate it are
not yet available. It is not known whether we will amend the plan in response to
the new legislation. In accordance with FASB Staff Position 106-2, we are
deferring the accounting for this Act and thus any measures of the accumulated
postretirement benefit obligation or net periodic postretirement benefit cost in
the consolidated financial statements or accompanying notes do not reflect the
effects of the Act on the plan. If current employer-sponsored plans are at least
actuarially equivalent to the Medicare Part D benefit, this Staff Position
states the effect of the subsidy on benefits attributable to past service would
result in an actuarial experience gain that would be amortized to earnings. The
effect of the subsidy on current service would reduce service cost. This
accounting is effective for the third quarter of 2004. Although we continue to
study the Act, we do not expect the impact on earnings to be material.
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. Effective with the
third quarter of 2004, this consensus also provides recognition and measurement
guidance regarding impairment of cost method investments. We have not determined
the impact of these new directives.
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. We are studying this rule.
3. Other Financial Information
o Revenues - During the second quarters of 2004 and 2003, approximately 27
percent and 25 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 six months ended
June 30, 2004 and 2003, these percentages were approximately 27 percent and
25 percent, respectively. Related purchase costs are classified as expense
in the crude oil, natural gas and product purchases category on the
consolidated earnings statement.
o Capitalized Interest - During the second quarters of 2004 and 2003,
capitalized interest totaled $10 million and $19 million, respectively. For
the six months ended June 30, 2004 and 2003, capitalized interest totaled
$26 million and $35 million, respectively. The decrease from the prior year
was related to development projects in Indonesia and Azerbaijan.
o Exploration Expense - Our exploration expense on the consolidated earnings
statement consisted of the following:
For the Three Months For the Six Months
Ended June 30, Ended June 30,
-------------------- ------------------
Millions of dollars 2004 2003 2004 2003
--------------------------------------------------------------------------------
Exploration operations $ 18 $ 16 $ 35 $ 31
Geological and geophysical 10 20 25 34
Amortization of exploratory
leasehold costs 16 47 32 71
Leasehold rentals 4 5 6 7
--------------------------------------------------------------------------------
Exploration expense $ 48 $ 88 $ 98 $ 143
================================================================================
-5-
Amortization of exploratory leasehold costs for the second quarter and six
month periods of 2004 was lower than the comparable periods 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 second quarter and six month periods of 2004 is principally
due to lower amortization levels for the Gulf of Mexico compared to the
same periods a year ago.
o Executive Stock Purchase Program - In the first quarter of 2004, we
repurchased 539,208 shares of our common stock from four of the original
participants of the Executive Stock Purchase Program of 2000 at market
prices in the first quarter of 2004. 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.
4. Dispositions Of Assets
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, minor working
interests, and subsurface mineral rights on approximately 3.3 million net acres,
located primarily in Texas, Louisiana, Mississippi, Arkansas and Alabama. 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.
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 7 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.
5. Restructuring
In 2003, we accrued $38 million pre-tax in restructuring charges and adopted a
plan for streamlining the 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 in the number of employees involved
in the restructuring and the subsequent reversal of $2 million pre-tax in
previously recognized costs. At June 30, 2004, 288 of 324 employees in the plan
had been terminated. The remaining 36 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 $12 million is
expected to be paid by the end of 2004.
Millions of dollars Number of Termination Training/
(except employees) Employees Costs Out-placement 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
================================================================================
-6-
6. Income Taxes
Income taxes on earnings from continuing operations for the second quarter and
six month periods of 2004 were $144 million and $323 million, respectively,
compared with $131 million and $297 million for the comparable periods of 2003.
The effective income tax rate for the second quarter and six month periods of
2004 was 34 percent and 37 percent, respectively, compared with 44 percent for
each of the same periods a year ago. The overall lower effective tax rates for
both the second quarter and six month periods of 2004, as compared to the same
periods a year ago, are due primarily to a net deferred tax benefit of $27
million recorded in the second quarter of 2004 for settlements and assessments
with various taxing authorities (see note 16 - "Tax Matters" for additional
detail) and the tax benefit effect in the second quarter of 2004 of currency
related adjustments in Thailand.
7. Discontinued Operations
In June 2004, we sold certain of our 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 $43 million.
The net proceeds received were $176 million after sale price adjustments to
reflect the effective date of the transaction as October 1, 2003. The gain on
the 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 the six month period of 2004 and revenues of $13
million and net earnings of approximately $6 million in the six month period of
2003.
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 and revenues of $1 million
and net earnings of approximately $0.4 million in the six 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 Six Months
Ended June 30, Ended June 30,
---------------------------------------------------
Millions of dollars 2004 2003 2004 2003
--------------------------------------------------------------------------------
Revenues $ 6 $ 7 $ 13 $ 14
Total costs and other deductions 1 1 3 3
--------------------------------------------------------------------------------
Earnings from discontinued
operations before income taxes 5 6 10 11
Income taxes on
discontinued operations 2 2 4 4
--------------------------------------------------------------------------------
Earnings from
discontinued operations 3 4 6 7
Gain on disposal of discontinued
operations before income taxes 84 13 84 13
Income taxes on disposal of
discontinued operations 28 5 28 5
--------------------------------------------------------------------------------
Gain on disposal of
discontinued operations 56 8 56 8
--------------------------------------------------------------------------------
Total earnings from
discontinued operations $ 59 $ 12 $ 62 $ 15
================================================================================
-7-
8. 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 second quarter and six month periods ended June
30, 2004 and 2003:
--------------------------------------------------------------------------------
Earnings Shares Per Share
Millions except per share amounts (Numerator) (Denominator) Amount
--------------------------------------------------------------------------------
Three months ended June 30, 2004
Earnings from continuing operations $ 282 263.9
Basic EPS $ 1.07
============
Effect of dilutive securities
Options and common stock equivalents 1.6
-----------------------
282 265.5 $ 1.06
Interest on convertible debentures
payable to trust (after-tax) 7 12.3
-----------------------
Diluted EPS $ 289 277.8 $ 1.04
============
Three months ended June 30, 2003
Earnings from continuing operations $ 165 258.2
Basic EPS $ 0.65
============
Effect of dilutive securities
Options and common stock equivalents 1.6
-----------------------
165 259.8 $ 0.64
Distributions on subsidiary trust
preferred securities (after-tax) 7 12.3
-----------------------
Diluted EPS $ 172 272.1 $ 0.64
============
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
Earnings Shares Per Share
Millions except per share amounts (Numerator) (Denominator) Amount
--------------------------------------------------------------------------------
Six months ended June 30, 2004
Earnings from continuing operations $ 548 262.9
Basic EPS $ 2.08
============
Effect of dilutive securities
Options and common stock equivalents 2.0
-----------------------
548 264.9 $ 2.07
Interest on convertible debentures
payable to trust (after-tax) 14 12.3
-----------------------
Diluted EPS $ 562 277.2 $ 2.03
============
Six months ended June 30, 2003
Earnings from continuing operations $ 379 258.1
Basic EPS $ 1.47
============
Effect of dilutive securities
Options and common stock equivalents 1.5
-----------------------
379 259.6 $ 1.46
Distributions on subsidiary trust
preferred securities (after-tax) 14 12.3
-----------------------
Diluted EPS $ 393 271.9 $ 1.45
============
--------------------------------------------------------------------------------
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 six month periods ended
June 30, 2004, there were options outstanding to purchase approximately 3.6
million and 2.5 million shares, respectively, of common stock that were excluded
from the computation of diluted EPS. In the three month and six month periods
ended June 30, 2003, there were options outstanding to purchase approximately
8.9 million and 10.5 million shares, respectively, of common stock that were
excluded from the computation of diluted EPS.
-8-
9. 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 subsidiary, Pure Resources, Inc. ("Pure"), 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 Months For the Six Months
Ended June 30, Ended June 30,
-----------------------------------------------------
Millions of dollars
except per share amounts 2004 2003 2004 2003
--------------------------------------------------------------------------------
Net earnings
As reported $ 341 $ 177 $ 610 $ 311
Add: Stock-based employee
compensation expense
included in reported net
income, net of related
tax effects and minority
interests 2 4 7 6
Deduct: Total stock-based
employee compensation
expense determined under
the fair value based
method for all awards,
net of related tax
effects and minority
interests (2) (6) (9) (10)
-----------------------------------------------------
Pro forma net earnings $ 341 $ 175 $ 608 $ 307
=====================================================
Net earnings per share:
Basic - as reported $ 1.29 $ 0.69 $ 2.32 $ 1.21
Basic - pro forma $ 1.29 $ 0.68 $ 2.31 $ 1.19
Diluted - as reported $ 1.25 $ 0.68 $ 2.25 $ 1.20
Diluted - pro forma $ 1.25 $ 0.67 $ 2.24 $ 1.18
10. Comprehensive Income
Unocal's comprehensive income is detailed in the following table:
For the Three Months For the Six Months
Ended June 30, Ended June 30,
-----------------------------------------------
Millions of dollars 2004 2003 2004 2003
--------------------------------------------------------------------------------
Net earnings $ 341 $ 177 $ 610 $ 311
Change in unrealized gain (loss)
on hedging instruments (a) (5) 7 (21) (3)
Reclassification adjustment for
settled hedging contracts (b) 17 4 9 11
Unrealized foreign currency
translation adjustments (21) 68 (30) 114
--------------------------------------------------------------------------------
Total comprehensive income $ 332 $ 256 $ 568 $ 433
================================================================================
(a) Net of tax effect of: (3) 4 (13) (2)
(b) Net of tax effect of: 10 2 5 6
-9-
11. Assets Held for Sale
As of June 30, 2004, we held for sale our interest in the Trans-Andean oil
pipeline, which transports crude oil from Argentina to Chile. This property is
part of our Midstream and Marketing segment and the investment represents
approximately $32 million in assets on our consolidated balance sheet.
In the second quarter of 2004, we sold certain of our prospective mineral fee
lands in North America (see note 7 - 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.
12. 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 six month periods ending June 30, 2004 and
June 30, 2003 were:
For the Three Months Ended June 30,
Pension Benefits Other Benefits
----------------- ----------------
Millions of dollars 2004 2003 2004 2003
--------------------------------------------------------------------------------
Service cost
(net of employee contributions) $ 8 $ 6 $ 1 $ 1
Interest cost 20 16 6 5
Expected return on plan assets (19) (16) - -
Amortization of:
Prior service cost 2 2 - -
Net actuarial (gains) losses 14 15 4 2
Curtailment and settlement (gains) losses - 3 - 1
--------------------------------------------------------------------------------
Net periodic pension and
other benefit cost (credit) $ 25 $ 26 $ 11 $ 9
================================================================================
For the Six Months Ended June 30,
Pension Benefits Other Benefits
----------------- ----------------
Millions of dollars 2004 2003 2004 2003
--------------------------------------------------------------------------------
Service cost
(net of employee contributions) $ 16 $ 13 $ 2 $ 2
Interest cost 40 36 13 11
Expected return on plan assets (38) (37) - -
Amortization of:
Prior service cost 3 3 - -
Net actuarial (gains) losses 30 30 7 5
Curtailment and settlement (gains) losses - 3 - 1
--------------------------------------------------------------------------------
Net periodic pension and
other benefit cost (credit) $ 51 $ 48 $ 22 $ 19
================================================================================
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
We are still in the process of evaluating the impact of the Medicare
Prescription Drug, Improvement and Modernization Act of 2003 on our U.S.
Postretirement Welfare plan. In keeping with the guidance provided by FASB Staff
Position 106-2, we have deferred accounting for this Act and thus the
measurement of the net periodic postretirement benefit cost at June 30, 2004
does not reflect the effects of the Act on the plan.
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.
-10-
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 June 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.
13. Long Term Debt
Unocal's total consolidated debt, including current maturities, was $3.34
billion at June 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
(see note 2 and note 14 for further detail).
During the six months period of 2004, we retired $173 million in 6.375% notes
and paid down $20 million of medium-term notes, which matured during the
quarter. In addition, we retired the remaining $24 million limited recourse loan
balance under the Azerbaijan International Operating Company's Early Oil Project
in the second quarter of 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 carried fixed rates that were 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.
14. 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.
Pursuant to FASB Interpretation No. 46 "Consolidation of Variable Interest
Entities" as revised in December 2003 (see note 2), 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.
-11-
15. Accrued Abandonment, Restoration and Environmental Liabilities
At June 30, 2004, we had accrued $739 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 $22 million in accrued
pre-tax accretion expense, $10 million in revisions to existing estimates and $6
million in new abandonment liabilities recorded during the period. Abandonment
liability settlements totaled $9 million during the first six months of 2004.
Our reserve for environmental remediation obligations at June 30, 2004 totaled
$249 million, of which $117 million was included in current liabilities. This
compared with $252 million at December 31, 2003, of which $118 million was
included in current liabilities.
16. 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 and financial
condition or liquidity.
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 15, at June 30, 2004, we had accrued $249 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
-12-
alternative remedies and/or ranges of costs, we estimate that we could incur
possible additional remediation costs aggregating approximately $210 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 six month period ended June 30, 2004, cash payments of $39 million
were applied against the reserves and $36 million in provisions were added to
the reserves. Possible additional remediation costs increased by $5 million
during the six month period of 2004. The accrued costs and the estimated
possible additional costs are shown below for four categories of sites:
At June 30, 2004
------------------------------------
Estimated Possible
Millions of dollars Reserve Additional Costs
--------------------------------------------------------------------------------
Superfund and similar sites $ 16 $ 15
Active Company facilities 32 30
Company facilities sold with retained
liabilities and former
Company-operated sites 93 80
Inactive or closed Company facilities 108 85
--------------------------------------------------------------------------------
Total $ 249 $ 210
================================================================================
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
-13-
At June 30, 2004, we have received notifications from the U.S.
Environmental Protection Agency ("EPA") that we may be a PRP at 24 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 18 sites, where we have
concluded that liability is probable and to the extent costs can be
reasonably estimated, a reserve of $13 million has been established for
future remediation and settlement costs.
Various state agencies and private parties had identified 21 other similar
PRP sites. Six 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 12 sites, a reserve of $3 million has been established for
future remediation and settlement costs.
The sites discussed above exclude 127 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.
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 $32 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 $8 million during the first six
months 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 the Company's 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 first six months of 2004, we made payments of $4
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:
-14-
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.
We have an aggregate reserve of $93 million for this group of sites. During
the first six months of 2004, provisions of $23 million for this category
were recorded. These provisions were primarily for approximately 200 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 first six months of 2004. Payments of $28 million
were made during the first six months 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 and York facilities in Pennsylvania
o the Beaumont Refinery in Texas.
A reserve of $108 million has been established for these types of
facilities. During the first six months of 2004, we accrued $4 million
related to sites in this category primarily for the Beaumont Refinery site.
A provision was recorded for the updated cost estimates to close
impoundments used in our former operations at this site. 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. Payments of $6 million
were made during the first six months 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 and York facilities in Pennsylvania pursuant to the
terms of their respective radioactive source materials licenses and
decommissioning plans.
We also must provide financial assurance for future closure and post-closure
costs of our RCRA-permitted facilities and for decommissioning costs at
facilities that are under radioactive source materials licenses. 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 $97 million at June 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
-15-
incur possible additional remediation costs aggregating approximately $55
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.
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. One of Agrium's expert witnesses testified in the
-16-
arbitration proceeding that Agrium's damages were in a range between $292
million and $708 million, depending upon different models. 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 plus $2 million in interest for underdelivery of natural gas
to the fertilizer plant through April 2004. Based on current delivery
projections from certain dedicated fields, we expect to reach the GPSA $50
million cap for liquidated damages over time for underdeliveries subsequent to
April 2004. 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.
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.
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.
-17-
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 anticipate receiving a cash refund of at
least $68 million, representing overpaid taxes plus interest thereon, in the
third quarter of 2004. 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.
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. Unocal anticipates receiving a cash refund of approximately $11
million representing overpaid taxes plus interest thereon, later this year.
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 June 30, 2004, the reserve for this category totaled $93 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.
-18-
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 June 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 $16 million.
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. Since 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 June 30, 2004, we had obtained
various surety bonds for $184 million. These surety bonds included a bond for
$72 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 $112 million
in various other routine performance bonds held by local, city, state and
federal agencies. We also had obtained $62 million in standby letters of credit
at June 30, 2004, of which $14 million represented additional collateral related
to the aforementioned 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.
-19-
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 $100 million at June 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.
17. 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 (the "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 $4 million at June 30, 2004 and $27 million
at December 31, 2003, and was reflected as a reduction to stockholders' equity
on the consolidated balance sheet.
18. 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 June 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, $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 June 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 first six months of 2004 due to ineffectiveness for
cash flow and fair value hedges. At June 30, 2004, we had approximately $23
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 July 2004 through December 2004. Nearly
all of the after-tax losses are expected to be reclassified to the consolidated
earnings statement during 2004.
Fair values for debt and other long-term instruments - The estimated fair values
of our long-term debt were $3.56 billion at June 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.
-20-
19. 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 14 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 June 30, 2004
Non-
Unocal Union Oil Guarantor
Millions of dollars (Parent) (Parent) Subsidiaries Eliminations Consolidated
---------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ 318 $ 1,833 $ (230) $ 1,921
Interest, dividends and miscellaneous income 1 1 19 (2) 19
Gain on sales of assets - (40) 80 - 40
---------------------------------------------------------------------------------------------------------------------
Total revenues 1 279 1,932 (232) 1,980
Costs and other deductions
Purchases, operating and other expenses 3 292 1,194 (231) 1,258
Depreciation, depletion and amortization - 65 175 - 240
Impairments - 3 6 - 9
Dry hole costs - 10 30 - 40
Interest expense 9 31 8 (2) 46
---------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 12 401 1,413 (233) 1,593
Equity in earnings of subsidiaries 350 443 - (793) -
Earnings from equity investments - 2 37 (1) 38
---------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 339 323 556 (793) 425
---------------------------------------------------------------------------------------------------------------------
Income taxes (2) (29) 175 - 144
Minority interests - - (1) - (1)
---------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 341 352 382 (793) 282
Earnings from discontinued operations - (2) 61 - 59
---------------------------------------------------------------------------------------------------------------------
Net earnings $ 341 $ 350 $ 443 $ (793) $ 341
=====================================================================================================================
-21-
CONDENSED CONSOLIDATED EARNINGS STATEMENT
For the Three Months Ended June 30, 2003
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-----------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ - $ 361 $ 1,518 $ (322) $ 1,557
Interest, dividends and miscellaneous income - 9 7 4 (11) 9
Gain on sales of assets - - 43 4 - 47
-----------------------------------------------------------------------------------------------------------------------
Total revenues - 9 411 1,526 (333) 1,613
Costs and other deductions
Purchases, operating and other expenses 3 - 341 1,036 (323) 1,057
Depreciation, depletion and amortization - - 78 176 - 254
Impairments - - 3 - - 3
Dry hole costs - - 6 4 - 10
Interest expense 9 1 29 7 (10) 36
Distributions on convertible preferred securities - 8 - - - 8
-----------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 12 9 457 1,223 (333) 1,368
Equity in earnings of subsidiaries 187 - 224 - (411) -
Earnings from equity investments - - 4 49 - 53
-----------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 175 - 182 352 (411) 298
-----------------------------------------------------------------------------------------------------------------------
Income taxes (2) - 3 130 - 131
Minority interests - - - 2 - 2
-----------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 177 - 179 220 (411) 165
Earnings from discontinued operations - - 8 4 - 12
-----------------------------------------------------------------------------------------------------------------------
Net earnings $ 177 $ - $ 187 $ 224 $ (411) $ 177
=======================================================================================================================
-22-
CONDENSED CONSOLIDATED EARNINGS STATEMENT
For the Six Months Ended June 30, 2004
Non-
Unocal Union Oil Guarantor
Millions of dollars (Parent) (Parent) Subsidiaries Eliminations Consolidated
---------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ 644 $ 3,543 $ (436) $ 3,751
Interest, dividends and miscellaneous income 1 5 27 (3) 30
Gain on sales of assets - (16) 100 - 84
---------------------------------------------------------------------------------------------------------------------
Total revenues 1 633 3,670 (439) 3,865
Costs and other deductions
Purchases, operating and other expenses 5 521 2,338 (437) 2,427
Depreciation, depletion and amortization - 128 344 - 472
Impairments - 6 8 - 14
Dry hole costs - 27 38 - 65
Interest expense 17 57 16 (3) 87
Distributions on convertible preferred securities - - - - -
---------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 22 739 2,744 (440) 3,065
Equity in earnings of subsidiaries 628 681 - (1,309) -
Earnings from equity investments - 3 73 (1) 75
---------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 607 578 999 (1,309) 875
---------------------------------------------------------------------------------------------------------------------
Income taxes (3) (52) 378 - 323
Minority interests - - 4 - 4
---------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 610 630 617 (1,309) 548
Earnings from discontinued operations - (2) 64 - 62
---------------------------------------------------------------------------------------------------------------------
Net earnings $ 610 $ 628 $ 681 $ (1,309) $ 610
=====================================================================================================================
-23-
CONDENSED CONSOLIDATED EARNINGS STATEMENT
For the Six Months Ended June 30, 2003
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-----------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ - $ 873 $ 3,201 $ (749) $ 3,325
Interest, dividends and miscellaneous income - 17 18 6 (21) 20
Gain on sales of assets - - 34 16 - 50
-----------------------------------------------------------------------------------------------------------------------
Total revenues - 17 925 3,223 (770) 3,395
Costs and other deductions
Purchases, operating and other expenses 5 - 623 2,246 (750) 2,124
Depreciation, depletion and amortization - - 184 329 - 513
Impairments - - 3 - - 3
Dry hole costs - - 58 23 - 81
Interest expense 17 1 59 17 (20) 74
Distributions on convertible preferred securities - 16 - - - 16
-----------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 22 17 927 2,615 (770) 2,811
Equity in earnings of subsidiaries 329 - 405 - (734) -
Earnings from equity investments - - 7 89 - 96
-----------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 307 - 410 697 (734) 680
-----------------------------------------------------------------------------------------------------------------------
Income taxes (4) - 34 267 - 297
Minority interests - - - 4 - 4
-----------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 311 - 376 426 (734) 379
Earnings from discontinued operations - - 8 7 - 15
Cumulative effect of accounting changes - - (55) (28) - (83)
-----------------------------------------------------------------------------------------------------------------------
Net earnings $ 311 $ - $ 329 $ 405 $ (734) $ 311
=======================================================================================================================
-24-
CONDENSED CONSOLIDATED BALANCE SHEET
At June 30, 2004
Non-
Unocal Union Oil Guarantor
Millions of dollars (Parent) (Parent) Subsidiaries Eliminations Consolidated
----------------------------------------------------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ 1 $ 360 $ 578 $ - $ 939
Accounts and notes receivable - net 120 273 1,043 (120) 1,316
Inventories - 8 213 (79) 142
Other current assets (1) 118 28 - 145
----------------------------------------------------------------------------------------------------------------------
Total current assets 120 759 1,862 (199) 2,542
Properties - net - 1,962 6,481 (3) 8,440
Other assets including goodwill 5,768 5,631 1,924 (11,828) 1,495
----------------------------------------------------------------------------------------------------------------------
Total assets $5,888 $ 8,352 $ 10,267 $ (12,030) $ 12,477
======================================================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ - $ 369 $ 899 $ (120) $ 1,148
Current portion of long-term debt - 162 74 - 236
Other current liabilities 56 225 439 (2) 718
----------------------------------------------------------------------------------------------------------------------
Total current liabilities 56 756 1,412 (122) 2,102
Long-term debt and capital leases 538 1,649 917 - 3,104
Deferred income taxes - (219) 943 - 724
Accrued abandonment, restoration
and environmental liabilities - 370 501 - 871
Other deferred credits and liabilities - 726 319 (3) 1,042
Minority interests - - 39 7 46
Stockholders' equity 5,294 5,070 6,136 (11,912) 4,588
----------------------------------------------------------------------------------------------------------------------
Total liabilities and stockholders' equity $5,888 $ 8,352 $ 10,267 $ (12,030) $ 12,477
======================================================================================================================
-25-
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
==============================================================================================================================
-26-
CONDENSED CONSOLIDATED CASH FLOWS
For the Six Months Ended June 30, 2004
Non-
Unocal Union Oil Guarantor
Millions of dollars (Parent) (Parent) Subsidiaries Eliminations Consolidated
---------------------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities $ 7 $ 613 $ 506 $ - $ 1,126
Cash Flows from Investing Activities
Capital expenditures and acquisitions
(includes dry hole costs) - (131) (670) - (801)
Proceeds from sales of assets
and discontinued operations - 28 250 - 278
Return of capital from affiliate company - - 48 - 48
---------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities - (103) (372) - (475)
---------------------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Change in long-term debt - (193) 87 - (106)
Dividends paid on common stock (105) - - - (105)
Proceeds from issuance of common stock 94 - - - 94
Repurchases of common stock (20) - - - (20)
Other 24 (2) (1) - 21
---------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities (7) (195) 86 - (116)
---------------------------------------------------------------------------------------------------------------------
Increase (decrease) in cash and cash equivalents - 315 220 - 535
---------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at beginning of period 1 45 358 - 404
---------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ 1 $ 360 $ 578 $ - $ 939
=====================================================================================================================
CONDENSED CONSOLIDATED CASH FLOWS
For the Six Months Ended June 30, 2003
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
--------------------------------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities $ 90 $ - $ 389 $ 606 $ - $ 1,085
Cash Flows from Investing Activities
Capital expenditures and acquisitions
(includes dry hole costs) - - (223) (694) - (917)
Proceeds from sales of assets
and discontinued operations - - 123 68 - 191
Return of capital from affiliate company - - - - - -
--------------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities - - (100) (626) - (726)
--------------------------------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Change in long-term debt and capital leases - - (114) 50 - (64)
Dividends paid on common stock (103) - - - - (103)
Proceeds from issuance of common stock 10 - - - - 10
Repurchases of common stock - - - - - -
Other 3 - (7) (3) - (7)
--------------------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities (90) - (121) 47 - (164)
--------------------------------------------------------------------------------------------------------------------------------
Increase in cash and cash equivalents - - 168 27 - 195
--------------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at beginning of period - - (18) 186 - 168
--------------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ - $ - $ 150 $ 213 $ - $ 363
================================================================================================================================
-27-
20. 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 June 30, 2004
----------------------------------------------------------------------------------------------------------------------
Millions of dollars U.S. Canada Total N.A. Asia Other Total Int'l Total E&P
----------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 197 $ 68 $ 265 $ 356 $ 79 $ 435 $ 700
Other income (loss) (a) 35 - 35 1 1 2 37
Inter-segment revenues 229 34 263 100 - 100 363
----------------------------------------------------------------------------------------------------------------------
Total 461 102 563 457 80 537 1,100
Earnings (loss) from equity investments - - - 12 2 14 14
Earnings (loss) from continuing operations 108 16 124 137 29 166 290
Earnings from discontinued operations (net) 46 - 46 - - - 46
----------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 154 16 170 137 29 166 336
Assets (at June 30, 2004) 3,210 1,267 4,477 3,529 927 4,456 8,933
----------------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------------
Midstream Geothermal Corporate and Other Total
and Net Environ-
Marketing Admin & Interest mental &
General Expense Litigation Other(b)
----------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 1,003 $ 124 $ - $ - $ - $ 94 $ 1,921
Other income (loss) (a) 3 13 - 4 - 2 59
Inter-segment revenues 4 - - - - (367) -
----------------------------------------------------------------------------------------------------------------------
Total 1,010 137 - 4 - (271) 1,980
Earnings (loss) from equity investments 12 (2) - - - 14 38
Earnings (loss) from continuing operations 18 57 (21) (33) (11) (18) 282
Earnings from discontinued operations (net) 13 - - - - - 59
----------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 31 57 (21) (33) (11) (18) 341
Assets (at June 30, 2004) 1,082 625 - - - 1,837 12,477
----------------------------------------------------------------------------------------------------------------------
(a) Includes interest, dividends and miscellaneous income, and gain (loss) on
sales of assets.
(b) Includes eliminations and consolidation adjustments.
-28-
----------------------------------------------------------------------------------------------------------------------
Segment Information Exploration and Production
For the Three Months North America International
Ended June 30, 2003
----------------------------------------------------------------------------------------------------------------------
Millions of dollars U.S. Canada Total N.A. Asia Other Total Int'l Total E&P
----------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 197 $ 37 $ 234 $ 321 $ 66 $ 387 $ 621
Other income (loss) (a) 46 - 46 - - - 46
Inter-segment revenues 284 41 325 72 - 72 397
----------------------------------------------------------------------------------------------------------------------
Total 527 78 605 393 66 459 1,064
Earnings (loss) from equity investments 6 - 6 11 - 11 17
Earnings (loss) from continuing operations 100 8 108 126 19 145 253
Earnings from discontinued operations (net) 4 - 4 - - - 4
----------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 104 8 112 126 19 145 257
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 $ 865 $ 28 $ - $ - $ - $ 43 $ 1,557
Other income (loss) (a) 1 2 - 6 - 1 56
Inter-segment revenues 3 - - - - (400) -
----------------------------------------------------------------------------------------------------------------------
Total 869 30 - 6 - (356) 1,613
Earnings (loss) from equity investments 17 4 - - - 15 53
Earnings (loss) from continuing operations 21 7 (22) (28) (28) (38) 165
Earnings from discontinued operations (net) - - - - - 8 12
----------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 21 7 (22) (28) (28) (30) 177
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.
-29-
----------------------------------------------------------------------------------------------------------------------
Segment Information Exploration and Production
For the Six Months North America International
Ended June 30, 2004
----------------------------------------------------------------------------------------------------------------------
Millions of dollars U.S. Canada Total N.A. Asia Other Total Int'l Total E&P
----------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 495 $ 139 $ 634 $ 708 $ 136 $ 844 $ 1,478
Other income (loss) (a) 45 - 45 2 2 4 49
Inter-segment revenues 435 66 501 202 - 202 703
----------------------------------------------------------------------------------------------------------------------
Total 975 205 1,180 912 138 1,050 2,230
Earnings (loss) from equity investments - - - 22 2 24 24
Earnings (loss) from continuing operations 221 28 249 295 46 341 590
Earnings from discontinued operations (net) 49 - 49 - - - 49
----------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 270 28 298 295 46 341 639
Assets (at June 30, 2004) 3,210 1,267 4,477 3,529 927 4,456 8,933
----------------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------------
Midstream Geothermal Corporate and Other Total
and Net Environ-
Marketing Admin & Interest mental &
General Expense Litigation Other(b)
----------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 1,984 $ 164 $ - $ - $ - $ 125 $ 3,751
Other income (loss) (a) 8 45 - 10 - 2 114
Inter-segment revenues 6 - - - - (709) -
----------------------------------------------------------------------------------------------------------------------
Total 1,998 209 - 10 - (582) 3,865
Earnings (loss) from equity investments 28 (1) - - - 24 75
Earnings (loss) from continuing operations 41 94 (48) (65) (27) (37) 548
Earnings from discontinued operations (net) 13 - - - - - 62
----------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 54 94 (48) (65) (27) (37) 610
Assets (at June 30, 2004) 1,082 625 - - - 1,837 12,477
----------------------------------------------------------------------------------------------------------------------
(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 Six Months North America International
Ended June 30, 2003
----------------------------------------------------------------------------------------------------------------------
Millions of dollars U.S. Canada Total N.A. Asia Other Total Int'l Total E&P
----------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 417 $ 95 $ 512 $ 653 $ 96 $ 749 $ 1,261
Other income (loss) (a) 49 - 49 - - - 49
Inter-segment revenues 672 79 751 163 - 163 914
----------------------------------------------------------------------------------------------------------------------
Total 1,138 174 1,312 816 96 912 2,224
Earnings (loss) from equity investments 9 - 9 20 4 24 33
Earnings (loss) from continuing operations 223 32 255 258 29 287 542
Earnings from discontinued operations (net) 7 - 7 - - - 7
Cumulative effect of accounting changes (b) (32) 4 (28) 13 - 13 (15)
----------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 198 36 234 271 29 300 534
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 $ 1,926 $ 63 $ - $ - $ - $ 75 $ 3,325
Other income (loss) (a) 1 2 - 10 - 8 70
Inter-segment revenues 5 - - - - (919) -
----------------------------------------------------------------------------------------------------------------------
Total 1,932 65 - 10 - (836) 3,395
Earnings (loss) from equity investments 33 5 - - - 25 96
Earnings (loss) from continuing operations 30 19 (45) (59) (45) (63) 379
Earnings from discontinued operations (net) - - - - - 8 15
Cumulative effect of accounting changes (b) (2) - - - - (66) (83)
----------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 28 19 (45) (59) (45) (121) 311
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.
21. Subsequent Events
On July 29, 2004, we sold our 50 percent equity interest in a jointly held
project company that owns UnoPaso Exploracao e Producao de Petroleo e Gas Ltda.,
a Brazilian exploration and production venture for $67 million plus possible
future payments. The underlying assets sold represent net production of
approximately 4.5 MBOE/d and represent our remaining oil and natural gas assets
in Brazil. We expect to record an after-tax gain of $1 million in the third
quarter of 2004.
On July 1, 2004, we sold property in Parachute, Colorado for $24 million in
cash. We expect to record an after-tax gain of $15 million in the third quarter
of 2004.
-31-
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. 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 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 20 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 asset sales from the
second quarter of 2004 and through the date of this report are listed below:
- Deepwater oil discovery drilled on the Tobago prospect in the Gulf of Mexico.
- 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.
- Ramp-up of production continued on the deepwater West Seno project in
Indonesia, although slower than initially forecast.
- Installed a floating storage unit for oil production from fields in the Gulf
of Thailand that resulted in decreased production during the installation
process.
- Construction of the Phase 1 and 2 developments of the Azerbaijan
International Operating Company ("AIOC") project in the Caspian Sea
progressed; first oil at the wellhead is expected in early 2005 for Phase 1.
- AIOC participant companies are reviewing for approval Phase 3 development and
official sanction is expected by year-end 2004.
- Approximately 70 percent of
the construction completed on the Baku-Tbilisi-Ceyhan ("BTC") export pipeline
from the Caspian Sea.
- Agreement reached in June 2004 to settle an eight-year dispute over operation
of the Tiwi and Mak-Ban geothermal steam fields in the Philippines.
- Certain mineral fee lands in the U.S. sold for $190 million.
- Arbitration panel decision received in dispute over our gas deliveries to
Agrium's Kenai, Alaska nitrogen-based fertilizer plant and Agrium's
obligation to reimburse us for royalties on the supplied natural gas.
Unocal is required to pay $36 million for past deliveries through April
2004 plus $2 million in interest. See note 16 under Part I, Item 1 of
this report.
- $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.
-32-
CONSOLIDATED RESULTS
The following table summarizes our consolidated net earnings for the second
quarter and six month periods ended June 30, 2004 and 2003:
For the Three Months For the Six Months
Ended June 30, Ended June 30,
-----------------------------------------------
Millions of dollars 2004 2003 2004 2003
--------------------------------------------------------------------------------
Earnings from continuing operations $ 282 $ 165 $ 548 $ 379
Earnings from discontinued operations 59 12 62 15
Cumulative effect of accounting changes - - - (83)
--------------------------------------------------------------------------------
Net earnings $ 341 $ 177 $ 610 $ 311
================================================================================
Earnings From Continuing Operations
Second Quarter Results: Earnings from continuing operations were $282
million in the second quarter of 2004, which was an increase of $117 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 $50 million and $35 million, respectively. In the
current quarter, our worldwide average realized liquids price was $32.61 per
Bbl, which was an increase of $7.25 per Bbl from the same period a year ago. Our
hedging program lowered the average realized liquids price by $1.94 per Bbl in
the current quarter while the prior year quarter included a loss of 4 cents per
Bbl from hedging activities. Our worldwide average realized natural gas price,
which included a loss of 11 cents per Mcf from hedging activities in the current
quarter, was $3.65 per Mcf. This was an increase of 12 cents per Mcf from the
$3.53 per Mcf realized during the same period a year ago, which included a loss
of 7 cents per Mcf from hedging activities. In addition, our Geothermal segment
settled an outstanding eight-year dispute over operation of the Tiwi and Mak-Ban
geothermal steam fields in the Philippines and recorded an after-tax settlement
gain of $46 million. We also recorded a net tax benefit of $27 million for
settlements and assessments with various taxing authorities. During the quarter,
our subsidiary, Pure Resources Inc., recorded a $23 million after-tax gain from
the sale of exploratory mineral fee lands. The second quarter of 2004 also
benefited from approximately $25 million after-tax in lower exploration expense
compared to the same period a year ago, primarily due to the higher amortization
of exploratory leasehold costs in 2003 resulting from the relinquishment of 44
deepwater blocks in the Gulf of Mexico. The second quarter of 2004 included a $1
million after-tax benefit from an adjustment to the 2003 company-wide
restructuring plan, which was recorded originally as a $17 million restructuring
charge in the second quarter of 2003.
These positive variance factors were partially offset by lower North America
production, which reduced net earnings by approximately $50 million in the
second quarter of 2004 compared with the same period a year ago. North America
liquids production averaged 70,000 Bbl/d in the second quarter of 2004, down
from 84,000 Bbl/d a year ago, while natural gas production averaged 594 MMcf/d
down from 805 MMcf/d for 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, dry hole costs were approximately $15 million higher in
the current quarter compared to the same period a year ago, primarily from
Indonesia and Thailand. 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. The second quarter of 2003 included a $20
million after-tax gain on the sale of our equity interest in Matador Petroleum
Corporation ("Matador"). Our after-tax environmental and litigation expenses
were $15 million in the second quarter of 2004, compared with $29 million in
2003.
Six Months Results: Earnings from continuing operations were $548
million in the first six months of 2004 compared to $379 million for the same
period a year ago. The increase was primarily due to higher worldwide natural
gas and liquids prices, which increased net earnings by approximately $70
million and $55 million, respectively. Our worldwide average realized natural
gas price, including a gain of 3 cents per Mcf from hedging activities, was
$3.92 per Mcf in the first six months of 2004. This was an increase of 21 cents
per Mcf, or 6 percent, from the $3.71 per Mcf, including a loss of 17 cents per
Mcf from hedging activities, realized during the first six months of 2003. In
the first six months of 2004, our worldwide average realized liquids price was
$31.41 per Bbl, which was an increase of $3.87 per Bbl, or 14 percent, from the
same period a year ago. Our hedging program lowered the average realized liquids
price by $1.45 per Bbl in the first six months of 2004 while the first six
months of 2003 included a loss of 26 cents per Bbl from
-33-
hedging activities. Exploration expenses and dry hole costs were lower in the
first six months 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 $40 million. In addition, the
first six months of 2004 included the aforementioned settlement gain of $46
million by our Geothermal segment. We also recorded the net tax benefit of $27
million recorded for settlements and assessments with various taxing
authorities.
These positive variance factors were partially offset by lower North America
production, which reduced net earnings by approximately $115 million in the
first six months of 2004. North America liquids production averaged 71,000 Bbl/d
in the first six months of 2004, down from 85,000 Bbl/d a year ago, while
natural gas production averaged 595 MMcf/d down from 833 MMcf/d for the six
months 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 and a field shut-in at the Mobile Bay area in the Gulf of Mexico due to
pipeline damage in the first quarter of 2004. We also recorded the
aforementioned provision of $29 million after-tax associated with the
arbitration ruling regarding Agrium's Kenai, Alaska nitrogen-based fertilizer
plant.
The first six months of 2004 included approximately $25 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 first six months of 2003 included
approximately $30 million in after-tax gains, primarily from the $20 million
after-tax gain on the sale of our equity interest in Matador. The first six
months of 2004 also included a $1 million after-tax benefit from an adjustment
to the 2003 company-wide restructuring plan, which was recorded originally as a
$17 million restructuring charge in the second quarter of 2003. After-tax
environmental and litigation expenses were $38 million in the first six months
of 2004, compared with $46 million in the same period a year ago.
Earnings From Discontinued Operations
Earnings from discontinued operations were $59 million and $12 million in the
second quarters of 2004 and 2003, respectively, and $62 million and $15 million
for the six month periods of 2004 and 2003, respectively.
The second quarter and six month periods of 2004 included approximately $43
million after-tax from our sale of certain mineral fee producing properties in
the United States and $13 million after-tax from our sale of the Cal Ven
pipeline located in Alberta, Canada. The remaining amounts in the second quarter
and six month periods of 2004 reflect after-tax earnings of $3 million and $6
million, respectively, from our operations in these mineral fee producing
properties and the Cal Ven pipeline prior to the sale. After-tax earnings from
the mineral fee producing properties and the Cal Ven pipeline were $4 million
and $7 million during the second quarter and six month periods of 2003,
respectively.
In the second quarter of 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.
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 second quarter of 2004 were $1.98
billion compared with $1.61 billion for the same period a year ago. In the first
six months of 2004, total revenues from continuing operations were $3.87 billion
compared with $3.40 billion for the same period a year ago. The increase in both
the second quarter and six month periods primarily reflected higher crude oil
and natural gas prices. This was partially offset by lower North America
production.
-34-
Income Taxes
Income taxes on earnings from continuing operations for the second quarter and
six month periods of 2004 were $144 million and $323 million, respectively,
compared with $131 million and $297 million for the comparable periods of 2003.
The effective income tax rate for the second quarter and six month periods of
2004 was 34 percent and 37 percent, respectively, compared with 44 percent for
both of the comparable periods of 2003. The overall lower effective tax rates
for both the second quarter and six months periods of 2004, as compared to 2003,
are due primarily to a net deferred tax benefit of $27 million recorded in the
second quarter of 2004 for settlements and assessments with various taxing
authorities and the tax benefit effect in the second quarter of 2004 of currency
related adjustments in Thailand.
The following table summarizes our net daily production and average prices for
our North America and International Exploration and Production business units:
OPERATING HIGHLIGHTS UNOCAL CORPORATION For the Three Months For the Six Months
Ended June 30, Ended June 30,
--------------------------------------
2004 2003 2004 2003
---------------------------------------------------------------------------------------------------------
North America Net Daily Production
Liquids (thousand barrels)
U.S. (a) 55 67 55 68
Canada 15 17 16 17
---------------------------------------------------------------------------------------------------------
Total liquids 70 84 71 85
Natural gas - dry basis (million cubic feet)
U.S. (a) 511 719 512 742
Canada 83 86 83 91
---------------------------------------------------------------------------------------------------------
Total natural gas 594 805 595 833
North America Average Prices (excluding hedging activities) (b)
Liquids (per barrel)
U. S. $ 35.91 $ 26.53 $ 33.66 $ 29.11
Canada $ 29.89 $ 23.52 $ 29.17 $ 26.05
Average $ 34.58 $ 25.93 $ 32.66 $ 28.48
Natural gas (per mcf)
U. S. $ 4.80 $ 4.64 $ 5.20 $ 5.25
Canada $ 5.40 $ 5.13 $ 5.37 $ 5.40
Average $ 4.88 $ 4.69 $ 5.23 $ 5.27
---------------------------------------------------------------------------------------------------------
North America Average Prices (including hedging activities) (b)
Liquids (per barrel)
U. S. $ 30.52 $ 26.41 $ 29.64 $ 28.49
Canada $ 29.89 $ 23.52 $ 29.17 $ 26.05
Average $ 30.38 $ 25.84 $ 29.54 $ 27.99
Natural gas (per mcf)
U. S. $ 4.53 $ 4.50 $ 5.34 $ 4.86
Canada $ 5.08 $ 4.79 $ 5.06 $ 5.07
Average $ 4.61 $ 4.53 $ 5.30 $ 4.89
---------------------------------------------------------------------------------------------------------
(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.
-35-
OPERATING HIGHLIGHTS (CONTINUED) For the Three Months For the Six Months
Ended June 30, Ended June 30,
--------------------------------------
2004 2003 2004 2003
---------------------------------------------------------------------------------------------------------
International Net Daily Production (c)
Liquids (thousand barrels)
Asia 61 59 64 58
Other (a) 20 20 20 20
---------------------------------------------------------------------------------------------------------
Total liquids 81 79 84 78
Natural gas - dry basis (million cubic feet)
Asia 891 977 885 968
Other (a) 31 23 28 22
---------------------------------------------------------------------------------------------------------
Total natural gas 922 1,000 913 990
International Average Prices (d)
Liquids (per barrel)
Asia $ 34.02 $ 24.77 $ 32.66 $ 27.06
Other $ 36.01 $ 25.19 $ 34.30 $ 27.10
Average $ 34.52 $ 24.90 $ 33.02 $ 27.07
Natural gas (per mcf)
Asia $ 3.02 $ 2.74 $ 2.99 $ 2.75
Other $ 4.01 $ 4.60 $ 4.17 $ 4.38
Average $ 3.03 $ 2.76 $ 3.01 $ 2.76
---------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------
Worldwide Net Daily Production (a) (c)
Liquids (thousand barrels) 151 163 155 163
Natural gas - dry basis (million cubic feet) 1,516 1,805 1,508 1,823
Barrels oil equivalent (thousands) 404 463 406 467
Worldwide Average Prices (excluding hedging activities) (b)
Liquids (per barrel) $ 34.55 $ 25.40 $ 32.86 $ 27.80
Natural gas (per mcf) $ 3.76 $ 3.60 $ 3.89 $ 3.88
Worldwide Average Prices (including hedging activities) (b)
Liquids (per barrel) $ 32.61 $ 25.36 $ 31.41 $ 27.54
Natural gas (per mcf) $ 3.65 $ 3.53 $ 3.92 $ 3.71
---------------------------------------------------------------------------------------------------------
(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.
-36-
BUSINESS SEGMENT RESULTS
See note 20 to the consolidated financial statements in Item 1 of this report
for details 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.
Second Quarter Results: After-tax earnings totaled $124 million in the
second quarter of 2004 compared to $108 million for the same period a year ago,
which was an increase of $16 million. Higher natural gas and liquids prices
contributed $35 million in higher earnings in the second quarter of 2004
compared with the quarter a year ago. Lower amortization of exploratory
leasehold costs in the second quarter of 2004 compared with the same period a
year ago increased earnings by approximately $20 million. These positive factors
were offset by lower natural gas and liquids production in the second quarter of
2004 compared with the same period a year ago, which reduced after-tax earnings
by approximately $50 million. The current quarter results included a $23 million
after-tax gain from the sale of certain of our exploratory mineral fee lands in
the United States, while the second quarter of 2003 included a $20 million
after-tax gain on the sale of our equity interest in Matador.
Six Months Results: After-tax earnings totaled $249 million in the
first six months of 2004 compared to $255 million for the same period a year
ago, which was a decrease of $6 million. Lower natural gas and liquids
production in the first six months of 2004 compared to the same period a year
ago reduced after-tax earnings by approximately $115 million. This factor was
partially offset by higher natural gas and liquids prices, which increased net
earnings by approximately $55 million in the first six months of 2004 compared
with the same period a year ago. In addition, exploration expenses and dry hole
costs were lower in the first six months 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.
The first six months of 2004 also included the $23 million after-tax
gain from the sale of certain of our exploratory mineral fee lands in the United
States and a $15 million litigation settlement related to a previous asset sale.
The six months results of 2003 included the $20 million after-tax gain on the
sale of our equity interest in Matador.
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, the Democratic
Republic of Congo and Brazil.
Second Quarter Results: After-tax earnings totaled $166 million in the
second quarter of 2004 compared to $145 million in the second quarter of 2003.
The increase was primarily due to higher liquids and natural gas prices, which
increased net earnings by approximately $40 million and $10 million,
respectively. These positive factors were partially offset by lower natural gas
production principally from Myanmar and Indonesia, which reduced after-tax
earnings by about $15 million. Higher dry hole costs reduced net earnings by
approximately $15 million, primarily from Indonesia and Thailand.
Six Months Results: After-tax earnings totaled $341 million in the
first six months of 2004 compared to $287 million in the first six months of
2003. The increase was primarily due to higher liquids and natural gas prices,
which increased net earnings by approximately $45 million and $25 million,
respectively. Higher liquids production benefited the 2004 results by adding
approximately $30 million to net earnings and was primarily due to the West Seno
production in Indonesia. These positive factors were partially offset by lower
natural gas production from Myanmar and Indonesia, which reduced after-tax
earnings by approximately $25 million. Higher dry hole costs reduced net
earnings by approximately $10 million, primarily from Indonesia and Thailand.
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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.
Second Quarter Results: Earnings from continuing operations totaled $18
million in the current quarter compared to $21 million in the second quarter of
2003. The results for the second quarter of 2004 reflect lower earnings from our
North American gas storage business and lower results from our pipeline
business.
The segment's sales and operating revenues were $1.01 billion in the
current quarter compared to $869 million in the same quarter a year ago.
Included in these totals were sales from marketing activities totaling $851
million in the current quarter compared to $738 million in the same quarter a
year ago, representing approximately 44 percent and 47 percent of our total
sales and operating revenues for the second quarters of 2004 and 2003,
respectively. The increase in sales from marketing activities was primarily due
to higher international and domestic crude oil revenues, which was partially
offset by lower domestic natural gas revenues attributable mainly to property
sales in 2003.
Six Months Results: Earnings from continuing operations totaled $41
million in the first six months of 2004 compared to $30 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 North
American gas storage business.
The segment's sales and operating revenues were $2.0 billion in the
first six months of 2004 compared to $1.93 billion in the same period a year
ago. Included in these totals were sales from marketing activities totaling
$1.68 billion in the current six month period compared to $1.66 billion in the
same period a year ago, representing approximately 45 percent and 50 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, which was mostly offset
by lower domestic natural gas revenues attributable mainly to property sales in
2003.
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.
Second Quarter Results: Earnings from continuing operations totaled $57
million in the current quarter compared to $7 million in the same period a year
ago. The current quarter results included a $46 million gain from the settlement
of the outstanding contract dispute in our Philippines operations (see "PGI
Settlement" below for further detail). The remaining increase was primarily due
to improved results from our operations at Gunung Salak on the island of Java,
Indonesia. The second quarter of 2003 reflects lost generation and additional
repair costs associated with damage caused by landslides at Gunung Salak.
Six Months Results: Earnings from continuing operations totaled $94
million in the first six months of 2004 compared to $19 million in the same
period a year ago. The 2004 results included the $46 million after-tax gain from
the settlement of the outstanding contract dispute in our Philippines operations
and the $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.
PGI Settlement: Our Philippines Geothermal, Inc. ("PGI") 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
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resources at Tiwi and Mak-Ban on the island of Luzon. In July, PGI received the
majority of all outstanding amounts owed by National Power Corporation and Power
Sector Assets and Liabilities Management Corporation.
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.
Second Quarter Results: The results for the current quarter were a loss
of $83 million compared to a loss of $116 million in the same period a year ago.
After-tax expenses for environmental and litigation matters for the current
quarter were $15 million compared to $29 million in the same period a year ago.
In the second quarter of 2004, we recorded 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. We also recorded a net tax benefit of $27
million for settlements and assessments with various taxing authorities. The
current quarter benefited from a $1 million after-tax benefit from an adjustment
to the 2003 company-wide restructuring plan, while the prior year quarter
included a $17 million restructuring charge (see note 5 to the consolidated
financial statements in Item 1 of this report).
Six Months Results: The results for the first six months of 2004 were a
loss of $177 million compared to a loss of $212 million in the same period a
year ago. After-tax expenses for environmental and litigation matters for the
six months of 2004 were $35 million compared to $46 million after-tax for the
same period a year ago. In the six month period of 2004, we recorded the
aforementioned provision of $29 million after-tax associated with the
arbitration ruling regarding Agrium's Kenai, Alaska nitrogen-based fertilizer
plant and the net tax benefit of $27 million for settlements and assessments
with various taxing authorities. The first six months of 2004 included the $1
million after-tax benefit from the adjustment to the 2003 company-wide
restructuring, which was originally recorded as a $17 million restructuring
charge in the second quarter of 2003.
LIQUIDITY AND CAPITAL RESOURCES
Cash and cash equivalents on hand totaled $939 million at June 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 in 2004 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 debt. In addition, we believe that our
available borrowing capacity is sufficient to enable us to meet any
unanticipated cash requirements if needed. As of the date of this report, there
are no material restrictions imposed by contracts or credit agreements that
would limit the movement of cash between Unocal and its consolidated
subsidiaries, equity investees or variable interest entities (including
restrictions on the payment of dividends or distributions) or otherwise have a
material impact on liquidity.
As announced on July 28, 2004, a program to spend up to $511 million in cash on
hand began in the third quarter of 2004. We have already made a $100 million
contribution to our U.S. pension plan on July 29, 2004. The remaining program,
if completed in full, would also consist of (a) repurchasing up to $150 million
of Unocal common stock from our previously announced and authorized $200 million
repurchase program (of which only approximately $11 million has been expended to
date) and (b) the redemption or other repurchase of up to 50 percent of the
aggregate liquidation value of the outstanding 6-1/4% Trust Convertible
Preferred Securities of the Trust (approximately $261 million).
Cash Flows from Operating Activities
Cash flows from operating activities, including working capital and other
changes, were $1.13 billion for the first six months ended June 30, 2004,
compared with $1.09 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 negative impact
from lower North America production, compared to the same period a year ago.
Changes in working capital during the first six months of 2004 reflect the
receipt of $35 million relating to a federal income tax refund related to
estimated payments for the 2003 tax year, the receipt of payment from the
Indonesian government in
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settlement of disputed value added taxes we paid in prior years and the
reduction in receivables from joint venture partners in the U.S. as a result of
asset sales in 2003.
Asset Sales
Pre-tax proceeds from asset sales relating to continuing and discontinued
operations were $278 million for the six months ended June 30, 2004. The current
year included net proceeds of $176 million from the sale of certain of our
mineral fee lands in the United States, $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 $23 million from the sale of various properties, primarily
in the Gulf of Mexico. Pre-tax proceeds from asset sales were $191 million for
the six months ended June 30, 2003. We received $80 million from the 2003 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 $105 million in proceeds.
Capital Expenditures and Other Investing Activities
Capital expenditures were $801 million for the first six months of 2004 compared
with $917 million in the same period a year ago. This year's expenditures level
primarily reflects lower development capital requirements in the Gulf of Mexico
deepwater. 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 first six months of 2004, capital expenditures
included approximately $335 million for the development of undeveloped proved
oil and gas reserves, primarily in Indonesia, Azerbaijan, Thailand and the
deepwater Gulf of Mexico.
In the first six months of 2004, cash flows from investing activities included
$52 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 first six months of 2004, we retired $173 million in 6.375% notes and
paid down $20 million of medium-term notes that matured during the second
quarter of 2004. In addition, we retired the remaining $24 million limited
recourse loan balance under the AIOC Early Oil Project in the second quarter of
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 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 carried fixed rates that were 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.
Credit Facilities and Other Financing Sources
We have two primary credit facilities in place: a $400 million 364-day credit
agreement, which is due to terminate on September 30, 2004, and a $600 million
credit agreement, which is due to terminate on October 31, 2006. No borrowings
were outstanding under either facility at June 30, 2004. Our ability to borrow
under these facilities is subject to the accuracy of certain representations and
warranties and the absence of any events of default that we believe are
customary for such facilities. The agreements provide for the termination of the
loan commitments and require the prepayment of all outstanding borrowings in the
event that (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 shall
cease to constitute at least a majority of the board. The agreements do not have
drawdown restrictions or prepayment obligations in the event of a credit rating
downgrade. Both agreements limit our total debt to total capitalization ratio to
70 percent (total capitalization is defined as total debt plus total equity,
with the convertible junior subordinated
-40-
debentures excluded from total debt and included as equity in the ratio
calculation.) We are currently negotiating a $1 billion five-year credit
facility to replace our existing $400 million and $600 million credit
agreements.
In addition, 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 June 30, 2004, the borrowing under the Canadian credit
facility translated to $223 million, using the applicable foreign exchange rate.
In addition to our revolving credit facilities, we have historically relied on
the commercial paper market and our accounts receivable securitization program
to cover near-term borrowing requirements. At June 30, 2004, we had no
outstanding balance under the accounts receivable securitization program. We
also have in place a universal shelf registration statement as of June 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 and market conditions. 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. We do not believe that we
have a significant exposure to liquidity risk in the event of a credit rating
downgrade.
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 16 to the consolidated financial statements for a detailed discussion.
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.
Costs associated with identified and reasonably estimable environmental
obligations have been accrued in a reserve for such obligations. At June 30,
2004, our reserves for environmental remediation obligations totaled $249
million, of which $117 million was included in current liabilities. During the
first six month period of 2004, cash payments of $39 million were applied
against the reserves and $36 million in provisions were 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 $210
million.
-41-
The reserve amounts and estimated possible additional costs are grouped into the
following four categories:
At June 30, 2004
------------------------------------
Estimated Possible
Millions of dollars Reserve Additional Costs
--------------------------------------------------------------------------------
Superfund and similar sites $ 16 $ 15
Active Company facilities 32 30
Company facilities sold with retained
liabilities and former
Company-operated sites 93 80
Inactive or closed Company facilities 108 85
--------------------------------------------------------------------------------
Total $ 249 $ 210
================================================================================
See notes 15 and 16 to the consolidated financial statements in Item 1 of this
report for additional information on environmental related matters.
During the first six months of 2004, provisions of $23 million were recorded for
the "Company facilities sold with retained liabilities and former
Company-operated sites" category. These provisions were primarily for
approximately 200 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 first six month of 2004.
We recorded provisions of $8 million during the first six months 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 the Company's 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.
We accrued $4 million related to sites in the "Inactive or closed Company
facilities" category during the first six months of 2004 primarily for our
former refinery in Beaumont, Texas. A provision was recorded for the updated
cost estimates to close impoundments used in the former operations at this site.
In the first six months 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.
In the first six months of 2004, estimated possible additional costs in excess
of amounts included in the reserves for remediation obligations increased by $5
million. The increase was for sites in the "Company facilities sold with
retained liabilities and former Company-operated sites" category. 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 assessments and
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 first six months of 2004.
-42-
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.
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,
especially events concerning Iraq, 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.
Our current outlook for full-year 2004 production is about 400,000 BOE per day
using a more conservative methodology than the prior estimate of 425,000 BOE per
day. The new outlook includes lower volumes due to dispositions of producing
assets in the United States and Brazil (4,000 BOE per day) and the impact of
higher prices on PSCs (3,000 BOE per day). The new outlook also reflects
infrastructure turnarounds and reduced performance at the West Seno field (8,000
BOE per day) plus other various factors (10,000 BOE per day).
Our current outlook of important 2004 operational activities is as follows:
Exploration and Production - North America
United States
o Two new deep water Gulf of Mexico developments are moving toward completion
in 2004. The Mad Dog field (operated by BP p.l.c. "BP") is expected to come
on stream in the second quarter of 2005. The K-2 field (operated by BP) is
expected to come on stream late in the first quarter of 2005 or early in
the second quarter of 2005. The estimate of initial net production is about
2,000 to 3,000 BOE/d from each field. We have a 15.6 percent working
interest in Mad Dog and a 12.5 percent working interest in K-2.
o In July, the first appraisal well on the deep water Gulf of Mexico St. Malo
discovery was completed on Walker Ridge Block 678. The well encountered
more than 400 net feet of oil pay at depths greater than were encountered
in the 2003 discovery well. We are currently evaluating the extensive test
data conducted on the well. 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 Sardinia prospect on
Keathley Canyon Block 681. Following Sardinia, we expect to drill a deeper
zone test called the Sequoia prospect below our Mirage discovery. 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.
o In Alaska, first production from our Happy Valley discovery is planned for
late 2004 upon completion of an extension of the Kenai Kachemak Pipeline.
Other natural gas prospects in the southern Kenai Peninsula are targeted
for exploration.
-43-
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 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 Pattani oil project is now underway. Upon
expected completion late in the second quarter of 2005 or early in the
third quarter of 2005, this project would add initially 7,000 BOE/d net and
is expected to rise to about 15,000 BOE/d by the end of 2005.
o We anticipate signing final agreements in 2004 or 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 is expected during 2004 with first production anticipated
in 2006.
Indonesia:
o At the West Seno field, we expect to complete Phase 1 drilling activities
by the end of 2004. In the fourth quarter, we expect to have a two week
shut down to make repairs to processing equipment. There are currently 20
wells completed and gross production averaged 24,000 BOE/d in June. By the
end of the year, 26 to 28 wells are expected to be on-line with an expected
gross exit rate of between 25,000 and 35,000 BOE/d. Bids were recently
opened for Phase 2 development, including offshore installation and tension
leg platform fabrication. We believe that the bid results were unacceptably
high. Accordingly, cost reduction options are being considered, and the
construction period will extend beyond 2005.
o We are continuing to work on solidifying our development plans for the
first deep water natural gas development project. Development will likely
be around two major hubs. First production is expected in late 2007 from
the Gendalo field where eight appraisal wells have been drilled to date.
The second development project is expected to be the Ranggas-Gehem oil and
gas complex where first production could come on-line in 2008.
o We expect exploration and appraisal drilling to continue in 2004 in the
deep water Kutei Basin. This drilling activity will test new areas in
recently awarded PSCs in the deep water.
Vietnam:
o We have recently signed a Heads of Agreement with PetroVietnam for natural
gas development. We fulfilled our drilling commitments in the second
quarter of 2004 and are continuing to work to bring Vietnam gas to market
between 2008 and 2010.
China:
o The evaluation of our PSC areas in the Xihu Trough off the coast of
Shanghai is in the process of being completed. Once the evaluation is
complete, we will make a determination whether we will participate in the
development program currently underway.
-44-
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 of 2005 or early in the second quarter of 2005. As a result
of the commencement of this new field, our net production is expected to
increase by 15,000 to 25,000 BOE/d over the remainder of 2005.
o We are currently negotiating for a third natural gas sales agreement in
Bangladesh covering the Bibiyana field. We expect to conclude negotiations
before year-end 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.
Other International
Azerbaijan:
o Progress continues in 2004 on the development of the BP operated AIOC
project. AIOC participant companies are reviewing Phase 3 and we expect
sanctioning of Phase 3 by year-end 2004. Phase 3, which is the deepwater
portion of the project, is the final phase of full field development. 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 additional net production from
Phase 1 development to begin in the second quarter at around 6,000 BOE/d
and end the year around 18,000 BOE/d.
Brazil:
o In July, we sold our 50 percent equity interest in a jointly held project
company that owns UnoPaso Exploracao e Producao de Petroleo e Gas Ltda., a
Brazilian exploration and production venture for $67 million plus possible
future payments. The underlying assets sold represent net production of
approximately 4.5 MBOE/d and represent our remaining oil and natural gas
assets in Brazil. We expect to record an after-tax gain of $1 million in
the third quarter of 2004.
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 first 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. As a result of this contribution, we expect
that the minimum pension liability for this plan at December 31, 2004, will be
considerably reduced from the $91 million recorded at year-end 2003. 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 would impact the reduction in minimum pension
liability and could accelerate the requirement to make cash contributions to the
plan before 2009.
FUTURE ACCOUNTING CHANGES
See note 2 to the consolidated financial statements for information about recent
accounting pronouncements.
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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 interest rates, foreign currency
exchange rates and commodity prices. 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 $22 million at June 30, 2004. The value at risk related to
hydrocarbon derivatives held for non-hedging purposes was immaterial at June 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 June 30, 2004. Assuming a ten percent decrease in our weighted
average borrowing costs at June 30, 2004, the potential increase in the fair
value of our debt obligations and associated interest
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rate derivative instruments, including the debt obligations and associated
interest rate derivative instruments of our subsidiaries, would have been
approximately $93 million at June 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 June 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 June 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 $30 million at June 30, 2004.
Hydrocarbon Derivatives Tables - The following tables set forth the future
volumes and price ranges of hydrocarbon derivatives we held at June 30, 2004,
along with the fair values of those instruments.
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Open Hydrocarbon Hedging Derivative Instruments (a)
(Thousands of dollars)
2004 2005 2006 2007-2008 Fair Value Asset
(Liability) (b)(c)
-----------------------------------------------------------------------------------------------------------------------------------
Natural Gas Futures Positions
Volume (MMBtu) 1,220,000 30,000 - - $ 1,996
Average price, per MMBtu $ 4.59 $ 5.01
Volume (MMBtu) (3,490,000) $ (397)
Average price, per MMBtu $ 6.22
-----------------------------------------------------------------------------------------------------------------------------------
Natural Gas Swap Positions
Pay fixed price
Volume (MMBtu) 9,096,000 11,393,000 7,218,000 14,459,000 $ 110,604
Average swap price, per MMBtu $ 3.85 $ 3.45 $ 2.42 $ 2.50
Receive fixed price
Volume (MMBtu) 38,240,000 3,650,000 - - $ (26,138)
Average swap price, per MMBtu $ 5.73 $ 6.31
-----------------------------------------------------------------------------------------------------------------------------------
Natural Gas Basis Swap Positions
Volume (MMBtu) 710,000 - - - $ 63
Average price received, per MMBtu $ 5.70
Average price paid, per MMBtu $ 5.69
-----------------------------------------------------------------------------------------------------------------------------------
Crude Oil Future position
Volume (Bbls) (2,020,000) - - - $ (4,630)
Average price, per Bbl $ 36.39
-----------------------------------------------------------------------------------------------------------------------------------
Crude Oil Collar Positions
Volume (Bbls) 360,000 - - - $ (4,074)
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 $1,878 thousand in assumed liabilities which were capitalized as
acquisition costs.
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Open Hydrocarbon Non-Hedging Derivative Instruments (a)
(Thousands of dollars)
2004 2005 2006 Fair Value Asset (Liability) (b)
---------------------------------------------------------------- --------------- -------------- ------------------------------------
Natural Gas Futures Positions
Volume (MMBtu) - - - $ -
Average price, per MMBtu $ -
Volume (MMBtu) (940,000) - - $ (1,333)
Average price, per MMBtu $ 5.64
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Swap Positions
Pay fixed price
Volume (MMBtu) 6,202,500 1,400,000 - $ 6,413
Average swap price, per MMBtu $ 5.42 $ 5.92
Receive fixed price
Volume (MMBtu) 5,455,988 1,400,000 - $ (6,862)
Average swap price, per MMBtu $ 5.29 $ 5.90
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Spread Swap Positions
Volume (MMBtu) 19,735,000 21,930,000 1,800,000 $ 1,741
Average price paid, per MMBtu $ 0.50 $ 0.73 $ 1.08
Volume (MMBtu) 20,500,000 20,710,000 - $ (1,536)
Average price received, per MMBtu $ 0.51 $ 0.71
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Option (Listed & OTC)
Call Volume -Buy-(MMBtu) 1,000,000 - - $ (614)
Average Call price $ 6.75
Call Volume -Sell-(MMBtu) 2,000,000 - - $ 558
Average Call price $ 6.65
Put Volume -Buy-(MMBtu) 3,340,000 - - $ (1,097)
Average Put Price $ 4.71
Put Volume -Sell-(MMBtu) 6,360,000 - - $ 69
Average Put Price $ 5.24
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Spread Option (Over the Counter)
NYMEX / IFERC (c)
Call Volume (MMBtu) - $ -
Average Strike price $ -
Put Volume (MMBtu) - 1,000,000 $ 628
Average Strike price $ - $ 0.50
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Future position
Volume (Bbls) 3,410,000 200,000 - $ 5,350
Average price, per Bbl $ 36.20 $ 29.92
Volume (Bbls) (3,210,000) (400,000) - $ (7,742)
Average price, per Bbl $ 36.11 $ 30.45
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Option (Listed & OTC)
Call Volumes -Buy-(Bbls) 400,000 - - $ (57)
Average price, per Bbl $ 44.25
Call Volumes -Sell-(Bbls) 500,000 - - $ 330
Average price, per Bbl $ 45.10
Put Volume -Buy-(Bbls) 200,000 - - $ (12)
Average price, per Bbl $ 36.00
Put Volume -Sell-(Bbls) 660,000 - - $ 563
Average price, per Bbl $ 27.27
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Swap Positions
Pay fixed price
Volume (Bbls) 6,086,304 915,920 38,640 $ 39,746
Average swap price, per Bbl $ 33.10 $ 27.61 $ 29.35
Receive fixed price
Volume (Bbls) 5,781,324 1,217,044 37,496 $(38,375)
Average swap price, per Bbl $ 33.10 $ 28.00 $ 27.28
====================================================================================================================================
(a) Futures positions reflect long (short) volumes.
(b) Includes $2,233 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).
-49-
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 June 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.
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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 period ended
March 31, 2004. The following is incorporated by reference: the information
regarding the environmental remediation reserve and possible additional
remediation costs in notes 15 and 16 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 16 to the consolidated
financial statements.
ITEM 2. CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY
SECURITIES.
The following table shows information regarding repurchases we made of our
shares of common stock during the second 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)
----------------------------------------------------------------------------------------------------------------------------
April 1 through April 30, 2004 28,324 $37.78 None $189,000,000
----------------------------------------------------------------------------------------------------------------------------
May 1 through May 31, 2004 30,706 $35.98 None $189,000,000
----------------------------------------------------------------------------------------------------------------------------
June 1 through June 30, 2004 49,469 $36.21 None $189,000,000
----------------------------------------------------------------------------------------------------------------------------
Total 108,499 $36.55 None $189,000,000
----------------------------------------------------------------------------------------------------------------------------
1. During the second quarter, we cancelled 13,662 shares repurchased for the
payment of withholding taxes due on restricted stock that vested under
various employee restricted stock plans.
During the second quarter, we purchased 94,837 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, the Board of Directors authorized the repurchase of $400
million of our common stock. In January 1998, the Board extended the stock
repurchase program, increasing the authorized amount by $200 million. There
is no expiration date to the repurchase program. A balance of approximately
$189 million remains for additional purchases. We expect to complete our
previously announced buyback program for up to $150 million of this $189
million balance by the end of 2004.
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ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
Our 2004 annual meeting of stockholders was held on May 24, 2004. The following
actions were taken by our stockholders at the annual meeting, for which proxies
were solicited pursuant to Regulation 14 under the Securities Exchange Act of
1934:
1. The three nominees proposed by our board of directors were elected as
directors by the following votes for three-year terms expiring at the
2007 annual meeting of stockholders, or until their successors are duly
elected and qualified:
Name Votes For Votes Withheld
Richard D. McCormick 235,792,241 3,373,105
Marina v.N. Whitman 234,355,351 4,809,995
Charles R. Williamson 231,857,993 7,307,353
2. A proposal to ratify the appointment of PricewaterhouseCoopers LLP as
Unocal's independent auditors for 2004 was passed by a vote of
234,111,927 (97.89%) for versus 3,424,384 (1.43%) against and 1,629,035
(0.68%) abstentions.
3. A proposal to approve the 2004 Management Incentive Program was passed
by a vote of 177,490,814 (81.82%) for versus 36,985,863 (17.05%)
against and 2,456,313 (1.13%) abstentions. There were 22,232,357 broker
non-votes.
4. A proposal to approve the 2004 Directors' Deferred Compensation and
Restricted Stock Unit Award Plan was passed by a vote of 201,235,643
(92.76%) for versus 13,196,432 (6.09%) against and 2,500,913 (1.15%)
abstentions. There were 22,232,359 broker non-votes.
5. A stockholder proposal requiring the Chairman of the Board not to serve
concurrently as the Chief Executive Officer was withdrawn by the
proponent and no vote was taken on that item.
6. A stockholder proposal to request the board of directors' compensation
committee to utilize performance and time-based restricted share
programs in lieu of stock options failed to pass, with a vote of
12,123,022 (5.59%) for versus 202,053,473 (93.14%) against and
2,756,492 (1.27%) abstentions. There were 22,232,360 broker non-votes.
7. A stockholder proposal to establish an office of the board of directors
for communications on corporate governance matters failed to pass, with
a vote of 44,257,798 (20.40%) for versus 169,139,423 (77.97%) against
and 3,535,768 (1.63%) abstentions. There were 22,232,358 broker
non-votes.
8. A stockholder proposal to request the board of directors to produce a
report to the stockholders on how Unocal is responding to rising
regulatory, competitive, and public pressure to significantly reduce
carbon dioxide and other greenhouse gas emissions failed to pass, with
a vote of 13,458,481 (6.20%) for versus 186,490,209 (85.97%) against
and 16,984,300 (7.83%) abstentions. There were 22,232,356 broker
non-votes.
ITEM 5. OTHER INFORMATION.
On July 21, 2004, we announced the hiring of Joseph H. Bryant as Unocal's
president and chief operating officer, effective September 1, 2004. Mr. Bryant
comes to Unocal with more than 27 years of experience in the industry, both
domestic and international. Since 2000, Mr. Bryant has been president of BP
Angola, one of BP's largest exploration and development operations. From
1997-2000, Mr. Bryant was president, Amoco Canada, and subsequently was named
president, BP Canada.
-52-
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits: The Exhibit Index on page 54 of this report lists the
exhibits that are filed or furnished, as applicable, as part of this
report.
(b) Reports on Form 8-K filed or furnished during the second quarter of
2004:
(1) Current Report on Form 8-K, dated and furnished April 28,
2004, for the purpose of reporting, under Items 9 and 12,
our first quarter 2004 earnings and related information.
(2) Current Report on Form 8-K, dated and filed May 25, 2004,
for the purpose of reporting under Items 5 and 7, the final
voting results from our 2004 annual meeting of stockholders.
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: August 5, 2004 By: /s/JOE D. CECIL
------------------------------
Joe D. Cecil
Vice President and Comptroller
(Duly Authorized Officer and
Principal Accounting Officer)
-53-
EXHIBIT INDEX
3. Bylaws of Unocal, as amended through May 24, 2004 and currently in
effect (incorporated by reference to Exhibit 4.2 to Unocal's
Registration Statement on Form S-8 filed June 7, 2004, File No.
333-116238).
10.1 2004 Directors' Deferred Compensation and Restricted Stock Unit Award
Plan (amended and restated effective as of May 24, 2004).
10.2 2004 Management Incentive Program (amended and restated effective as of
July 28, 2004).
10.3 Employment Agreement, effective as of July 20, 2004, by and between
Unocal and Joseph H. Bryant.
12.1 Statement regarding computation of ratio of earnings to fixed charges
of Unocal Corporation for the six months ended June 30, 2004 and 2003.
12.2 Statement regarding computation of ratio of earnings to fixed charges
of Union Oil Company of California for the six months ended June 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.
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