UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2003
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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 par value, outstanding as of
October 31, 2003: 258,951,128
TABLE OF CONTENTS
PAGE
Glossary.................................................................... i
PART I FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Earnings............................................. 1
Consolidated Balance Sheet........................................ 2
Consolidated Cash Flows........................................... 3
Notes to Financial Statements..................................... 4
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations....................... 38
Operating Highlights ............................................... 40
Item 3. Quantative and Qualitative Disclosures About Market Risk............ 56
Item 4. Controls and Procedures............................................. 60
PART II OTHER INFORMATION
Item 1. Legal Proceedings................................................... 61
Item 5. Other Information................................................... 61
Item 6. Exhibits and Reports on Form 8-K.................................... 62
SIGNATURE................................................................... 63
EXHIBIT INDEX............................................................... 64
GLOSSARY
Below are certain definitions of key terms that may be in use in this Form 10-Q
report.
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
CF Cubic feet Btu British thermal units
BOE Barrels of oil equivalent DD&A Depreciation, depletion
and amortization
Liquids Crude oil, condensate and NGLs NGLs Natural gas liquids
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, which 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 the same
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 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 the Company's share of the cost recovery revenue and the
profit revenue is divided by market oil and gas prices and represents the
volume that the Company is entitled to. 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 desires to drill on the leased acreage. The assignor
usually retains a royalty or reversionary interest in the lease. 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 subsea completion wells are brought by flowlines to
the vessel where they are separated, treated, stored and then offloaded to
another vessel for transportation.
o Gross acres or gross wells are the total acres or wells in which a working
interest is owned.
i
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 actually be more or less than actual
entitlements that are 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 pressure 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 the Company's 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 Production Sharing Contract ("PSC") is a contractual agreement between the
Company and a host government whereby the Company, acting as contractor,
bears all exploration costs, development and production costs in return for
an agreed upon share of the proceeds from the sale of production.
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
such production exceed production expenses and taxes.
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 prospects.
o Working interest is the percentage of ownership that the Company has in a
joint venture, partnership, consortium, project or acreage.
ii
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CONSOLIDATED EARNINGS (UNAUDITED) UNOCAL CORPORATION
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
-------------------------------------------------
Millions of dollars
except per share amounts 2003 2002 2003 2002
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Revenues
Sales and operating revenues $ 1,478 $ 1,299 $ 4,817 $ 3,695
Interest, dividends
and miscellaneous income (2) (3) 18 17
Gain on sales of assets 65 1 115 2
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Total revenues 1,541 1,297 4,950 3,714
Costs and other deductions
Crude oil, natural gas
and product purchases 447 401 1,629 1,124
Operating expense 346 326 965 949
Administrative and general expense 61 34 199 114
Depreciation, depletion and amortization 231 245 746 724
Asset impairments 83 6 86 27
Dry hole costs 14 40 95 81
Exploration expense 39 60 182 180
Interest expense 45 40 119 134
Property and other operating taxes 18 7 61 41
Distributions on convertible preferred
securities of subsidiary trust 8 8 24 24
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Total costs and other deductions 1,292 1,167 4,106 3,398
Earnings from equity investments 54 35 150 123
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Earnings from continuing operations
before income taxes
and minority interests 303 165 994 439
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Income taxes 147 68 448 203
Minority interests 4 (2) 8 2
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Earnings from continuing operations 152 99 538 234
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Earnings from discontinued operations - - 8 1
Cumulative effects of
accounting changes (a) - - (83) -
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Net earnings $ 152 $ 99 $ 463 $ 235
================================================================================
Basic earnings per share
of common stock (b)
Continuing operations $ 0.59 $ 0.41 $ 2.08 $ 0.96
Net earnings $ 0.59 $ 0.41 $ 1.79 $ 0.96
Diluted earnings per share
of common stock (c)
Continuing operations $ 0.58 $ 0.41 $ 2.05 $ 0.96
Net earnings $ 0.58 $ 0.41 $ 1.78 $ 0.96
Cash dividends declared per share
of common stock $ 0.20 $ 0.20 $ 0.60 $ 0.60
--------------------------------------------------------------------------------
(a) Net of tax (benefit) $ - $ - $ (48) $ -
(b) Basic weighted average shares
outstanding (in thousands) 258,525 244,664 258,244 244,503
(c) Diluted weighted average shares
outstanding (in thousands) 272,691 245,226 272,172 245,378
See Notes to the Consolidated Financial Statements.
-1-
CONSOLIDATED BALANCE SHEET UNOCAL CORPORATION
At September 30, At December 31,
-------------------------------------
Millions of dollars 2003 (a) 2002
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Assets
Current assets
Cash and cash equivalents $ 485 $ 168
Accounts and notes receivable - net 1,009 994
Inventories 132 97
Deferred income taxes 122 90
Other current assets 31 26
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Total current assets 1,779 1,375
Investments and long-term receivables - net 903 1,044
Properties - net (b) 8,492 7,879
Goodwill 129 122
Deferred income taxes 261 210
Other assets 146 130
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Total assets $ 11,710 $ 10,760
================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ 1,044 $ 1,024
Taxes payable 278 223
Dividends payable 51 51
Interest payable 52 50
Current portion of environmental liabilities 144 113
Current portion of long-term debt
and capital leases 249 6
Other current liabilities 159 165
--------------------------------------------------------------------------------
Total current liabilities 1,977 1,632
Long-term debt and capital leases 2,868 3,002
Deferred income taxes 709 593
Accrued abandonment, restoration
and environmental liabilities 912 622
Other deferred credits and liabilities 915 816
Minority interests 28 275
Commitments and contingencies - Note 17
Company-obligated mandatorily redeemable
convertible preferred securities
of a subsidiary trust holding
solely parent debentures 522 522
Common stock ($1 par value,
shares authorized: 750,000,000 (c)) 269 269
Capital in excess of par value 985 962
Unearned portion of restricted stock issued (14) (20)
Retained earnings 3,329 3,021
Accumulated other comprehensive income (353) (486)
Notes receivable - key employees (26) (37)
Treasury stock - at cost (d) (411) (411)
--------------------------------------------------------------------------------
Total stockholders' equity 3,779 3,298
--------------------------------------------------------------------------------
Total liabilities and stockholders' equity $ 11,710 $ 10,760
================================================================================
(a) Unaudited
(b) Net of accumulated depreciation,
depletion and amortization of: $ 13,120 $ 12,277
(c) Number of shares outstanding (in thousands) 258,718 257,980
(d) Number of shares (in thousands) 10,623 10,623
The Company follows the successful efforts method of accounting for its oil and
gas activities.
See Notes to the Consolidated Financial Statements.
-2-
CONSOLIDATED CASH FLOWS (UNAUDITED) UNOCAL CORPORATION
For the Nine Months
Ended September 30,
----------------------
Millions of dollars 2003 2002
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Cash Flows from Operating Activities
Net earnings $ 463 $ 235
Adjustments to reconcile net earnings to
net cash provided by operating activities
Depreciation, depletion and amortization 746 724
Asset impairments 86 27
Dry hole costs 95 81
Amortization of exploratory leasehold costs 88 74
Deferred income taxes 102 25
Gain on sales of assets (115) (2)
Gain on disposal of discontinued operations (13) (2)
Pension expense 65 17
Restructuring provisions net of payments 22 14
Cumulative effect of accounting changes 83 -
Other 5 (85)
Working capital and other changes
related to operations
Accounts and notes receivable (15) 160
Inventories (35) (2)
Accounts payable 20 44
Taxes payable 55 4
Other 1 (82)
--------------------------------------------------------------------------------
Net cash provided by operating activities 1,653 1,232
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Cash Flows from Investing Activities
Capital expenditures (includes dry hole costs) (1,296) (1,248)
Proceeds from sales of assets 343 61
Proceeds from sale of discontinued operations 11 3
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Net cash used in investing activities (942) (1,184)
--------------------------------------------------------------------------------
Cash Flows from Financing Activities
Long-term borrowings 154 437
Reduction of long-term debt
and capital lease obligations (156) (267)
Minority interests (257) (6)
Proceeds from issuance of common stock 15 19
Dividends paid on common stock (155) (147)
Other 5 1
--------------------------------------------------------------------------------
Net cash provided by (used in) financing activities (394) 37
--------------------------------------------------------------------------------
Net increase (decrease) in cash and cash equivalents 317 85
--------------------------------------------------------------------------------
Cash and cash equivalents at beginning of year 168 190
--------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ 485 $ 275
================================================================================
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized) $ 123 $ 136
Income taxes (net of refunds) $ 310 $ 211
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 management, include all adjustments necessary for a fair
presentation of financial position and results of operations. All adjustments
are of a normal recurring nature. Such financial statements are presented in
accordance with the Securities and Exchange Commission's ("SEC") disclosure
requirements for Form 10-Q.
These interim consolidated financial statements should be read in conjunction
with the consolidated financial statements and the related notes filed with the
SEC in Unocal Corporation's 2002 Annual Report on Form 10-K.
For the purpose of this report, Unocal Corporation ("Unocal") and its
consolidated subsidiaries, including Union Oil Company of California ("Union
Oil"), are referred to as the "Company."
The consolidated financial statements of the Company include the accounts of
subsidiaries in which a controlling interest is held. Investments in entities
without a controlling interest are accounted for by the equity method or cost
basis. Under the equity method, the investments are stated at cost plus the
Company's equity in undistributed earnings and losses after acquisition. Income
taxes estimated to be payable when earnings are distributed are included in
deferred income taxes.
Results for the nine months ended September 30, 2003, are not necessarily
indicative of future financial results.
Certain items in the financial statements of the prior periods have been
reclassified to conform to the 2003 presentation.
2. Accounting Changes
SFAS No. 143: Effective January 1, 2003, the Company adopted Statement of
Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset
Retirement Obligations." If a reasonable estimate of fair value can be made,
this Statement requires that the Company recognize liabilities related to the
legal obligations associated with the retirement of its tangible long-lived
assets in the periods in which the obligations are incurred (typically when the
assets are installed). These obligations include the required decommissioning
and removal of certain oil and gas platforms, plugging and abandonment of oil
and gas wells and facilities and the closure and site restoration of certain
mining facilities. The recognized liability amounts are based upon future
retirement cost estimates and incorporate many assumptions such as expected
economic recoveries of crude oil and natural gas, time to abandonment, future
inflation rates and the risk free rate of interest adjusted for the Company's
credit costs.
The Company has interests in some long-lived assets, such as commercial natural
gas storage facilities, commercial crude oil and products storage facilities,
commercial pipelines, etc. where the operations are not tied to any particular
operating field reserves. As the Company expects these assets to continue
operations for the foreseeable future, it cannot reasonably estimate when, or
if, these facilities will be abandoned. Accordingly, the Company has not accrued
abandonment and restoration liabilities for these assets. The Company will
continue to monitor these assets for any changes to this position.
Prior to January 1, 2003, the Company was required under SFAS No. 19, "Financial
Accounting and Reporting by Oil and Gas Producing Companies," to accrue its
abandonment and restoration costs ratably over the productive lives of its
assets using the units-of-production method. SFAS No. 19 resulted in higher
costs being accrued early in the fields' lives when production was at its
highest levels and abandonment and restoration costs accruals were matched with
the revenues as oil and gas were produced.
-4-
Under SFAS No. 143, when the liabilities for asset retirement obligations are
initially recorded at their fair value, capital costs of the related assets will
be increased by equal corresponding amounts. Over time, changes in the present
value of the liabilities will be accreted and expensed and the capitalized asset
costs will be depreciated over the useful lives of the corresponding assets.
Because SFAS No. 143 requires the use of interest accretion for revaluing asset
retirement obligation liabilities as a result of the passage of time, associated
accretion costs will be higher near the end of the fields' lives when oil and
gas production and related revenues are at their lowest levels.
Accounting Principles Board ("APB") Opinion No. 20, "Accounting Changes"
requires that the Company calculate the retroactive impact of adopting SFAS No.
143 from the inception of its asset retirement obligations to its January 1,
2003 adoption date. APB Opinion No. 20 requires that this impact be quantified
and reported as a cumulative effect of an accounting change on the earnings
statement. This cumulative effect includes the catch up of SFAS No. 143
accretion expense related to the fair value of the liabilities as well as the
catch up of associated depreciation expense related to the increased capital
costs of the corresponding assets. The cumulative effect also includes the
reversal of abandonment and restoration costs previously charged to earnings
under SFAS No. 19. In addition to the impact on earnings due to the differences
in applying SFAS No. 19 and SFAS No. 143 to the Company's oil and gas
operations, the cumulative effect also includes the impact related to the
Company's mining operations under SFAS No. 143.
In the first quarter of 2003, the Company recognized a one time after-tax charge
of $83 million as the cumulative effect of an accounting change related to the
adoption of SFAS No. 143. The Company also increased its accrued abandonment and
restoration liabilities by $268 million and increased its net properties by $138
million on the consolidated balance sheet as a result of the adoption of SFAS
143 as of January 1, 2003. The Company estimates that the impact of adopting
SFAS No. 143 on its 2003 operating earnings will be an incremental charge of
approximately $10 million after tax.
Listed below is SFAS No. 143 pro-forma liability and earnings information for
the periods ended December 31, 2000, 2001 and 2002 and September 30, 2002:
Pro Forma SFAS 143 liability carrying
amounts for the periods shown
(Millions of dollars) 2000 2001 2002
--------------------------------------------------------------------------------
Carrying amount of liability at beginning of year $629 $661 $713
--------------------------------------------------------------------------------
Carrying amount of liability at end of period $661 $713 $758
--------------------------------------------------------------------------------
Pro Forma amounts assuming SFAS 143
was applied retroactively
Millions of dollars
(except per share amounts)
For the years ended For the Nine
December 31, Months Ended
2000 2001 2002 Sep. 30, 2002
--------------------------------------------------------------------------------
Net income as reported $760 $615 $331 $235
Earnings per share as reported:
Basic $3.13 $2.52 $1.34 $0.96
Diluted $3.08 $2.50 $1.34 $0.96
Pro forma net income $740 $596 $312 $221
Pro forma earnings per share:
Basic $3.05 $2.44 $1.26 $0.90
Diluted $3.00 $2.42 $1.26 $0.90
--------------------------------------------------------------------------------
SFAS No. 146: Effective January 1, 2003, the Company adopted SFAS No. 146,
"Accounting for Costs Associated with Exit or Disposal Activities." This
Statement provides guidance on the recognition and measurement of liabilities
associated with disposal activities. The adoption of the Statement did not have
a material effect on the Company's financial position or results of operations.
-5-
SFAS No. 148: Effective January 1, 2003, the Company adopted SFAS No. 148,
"Accounting for Stock-Based Compensation--Transition and Disclosure--an
amendment of FASB Statement No. 123." The Statement provides for three methods
of transitioning from the intrinsic value to the fair value method of accounting
for stock-based compensation. This Statement also amended the disclosure
requirements of SFAS No. 123 and APB Opinion No. 28, "Interim Financial
Reporting," to require prominent disclosures in both annual and interim
financial statements about the method of accounting for stock-based employee
compensation and the effect of the method used on reported results. The
disclosure requirements of the Statement were adopted in the Company's 2002
Annual Report on Form 10-K. The Company adopted the fair value recognition
provisions of SFAS No. 148, on a prospective basis, effective January 1, 2003
(see note 9 for further details). This change is estimated to decrease 2003
after-tax income by approximately $6 million. Adoption of the fair value
recognition provisions will not have a material effect on the Company's 2003
financial position or results of operations.
SFAS No. 149: Effective July 1, 2003, the Company adopted SFAS No. 149,
"Amendment of Statement 133 on Derivative Instruments and Hedging Activities."
This Statement amends and clarifies accounting for derivative instruments
including certain derivative instruments embedded in other contracts, and for
hedging activities under SFAS No. 133. The adoption of the Statement did not
have a material effect on the Company's financial position or results of
operations.
SFAS No. 150: Effective April 1, 2003, the Company adopted SFAS No. 150,
"Accounting for Certain Instruments with Characteristics of Both Liabilities and
Equity," which establishes standards for how an issuer classifies and measures
certain financial instruments with characteristics of both liabilities and
equity. SFAS No. 150 requires that the Company classify a financial instrument
that is within its scope, which may have previously been reported as equity, as
a liability or an asset in some circumstances. The adoption of the Statement did
not have an effect on the Company's financial position.
FASB Interpretation No. 45: Effective January 1, 2003, the Company adopted FASB
Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of Others." This
Interpretation requires the recognition of certain guarantees as liabilities at
fair market value and is effective for guarantees issued or modified after
December 31, 2002. The Company has included the disclosure requirements of the
Interpretation in note 17. The adoption of this Interpretation did not have a
material effect on the Company's financial position or results of operations.
FASB Interpretation No. 46: Effective January 1, 2003, the Company adopted FASB
Interpretation No. 46, "Consolidation of Variable Interest Entities." This
Interpretation requires the consolidation of certain entities that generally
lack sufficient equity to finance their own activity without support from others
or where there is an absence of control by equity investors. This Interpretation
was effective for new variable interest entities as of February 1, 2003.
Effective July 1, 2003, the Company adopted the Interpretation for the entities
that existed prior to February 1, 2003. The Company has included the disclosure
requirements of the Interpretation in this report. Pursuant to the recognition
requirements of FASB Interpretation No. 46, the Company consolidated in the
third quarter of 2003 the long-term debt of an affiliate that operates
geothermal steam-fired power plants in Indonesia. At September 30, 2003, the
balance sheet includes $78 million related to this debt (see note 15 for further
details). An additional $242 million, classified as minority interests as of
June 30, 2003, related to a partnership interest in Spirit Energy 76
Development, L.P. ("Spirit LP"), would have been required to be consolidated as
long-term debt under this Interpretation had it not been paid in July 2003. In
addition, because of the complexities of this rule and the FASB deferral, as set
forth in FASB Staff Position No. FIN 46-6, of mandatory adoption until
December 31, 2003, the Company continues to review and may find additional
material interests in entities which could require recognition or disclosure
in the financial statements.
-6-
Other Matters: Consistent with SFAS No. 19, "Financial Accounting and Reporting
by Oil and Gas Producing Companies," costs of acquiring oil and gas drilling
rights have been classified as tangible assets in property, plant and equipment.
The Company understands the staff of the SEC believes SFAS No. 19 does not
provide guidance as to whether these assets should be classified as tangible or
intangible and therefore believe SFAS No. 141, "Business Combinations," and SFAS
No. 142, "Goodwill and Other Intangible Assets," would require that drilling
rights be classified as an intangible asset. The SEC has requested the FASB to
address this perceived conflict within the related FASB statements. The
resolution of this issue will have no impact on the Company's results of
operations. If the FASB concurs with the SEC, it would result in additional
disclosures and a balance sheet reclassification of these assets from
Properties-net to Intangible Assets.
3. Other Financial Information
During the third quarters of 2003 and 2002, approximately 20 percent and 24
percent, respectively, of total sales and operating revenues were attributable
to the resale of liquids and natural gas purchased from others in connection
with marketing activities. For the nine months ended September 30, 2003 and
2002, these percentages were each approximately 23 percent. Related purchase
costs are classified as expense in the crude oil, natural gas and product
purchase category on the consolidated earnings statement.
Capitalized interest totaled $11 million and $14 million for the third quarters
of 2003 and 2002, respectively. For the nine months ended September 30, 2003 and
2002, capitalized interest totaled $46 million and $33 million, respectively.
The increase for the comparative nine months periods was primarily due to the
capitalized interest related to the Azerbaijan International Operating Company
("AIOC") development of Phase I of the offshore Azeri field in the
Azeri-Chirag-Gunashli structure in the Azerbaijan sector of the Caspian Sea.
Exploration expense on the consolidated earnings statement consisted of the
following:
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
-------------------- -------------------
Millions of dollars 2003 2002 2003 2002
--------------------------------------------------------------------------------
Exploration operations $ 13 $ 18 $ 44 $ 66
Geological and geophysical 7 10 41 29
Amortization of exploratory leasehold costs 17 29 88 74
Leasehold rentals 2 3 9 11
--------------------------------------------------------------------------------
Exploration expense $ 39 $ 60 $182 $180
================================================================================
For the nine months ended September 30, 2003, amortization of exploratory
leasehold costs included a $26 million pre-tax provision that was a result of
the Company's relinquishment of 44 deepwater Gulf of Mexico blocks before their
expiration dates. The Company intends to focus its deepwater Gulf of Mexico land
position on those Outer Continental Shelf blocks that have the best potential.
The prior year nine months period included a provision of $14 million pre-tax
reflecting the relinquishment of exploration blocks in Brazil and Gabon.
-7-
4. Dispositions Of Assets
In the third quarter of 2003, the Company's Chicago Carbon Company subsidiary
sold 4.9 million of the common shares it held in Tom Brown, Inc. ("TBI"). The
sale was part of the underwritten stock offering commenced by TBI in early
September and represented approximately 85 percent of the 5.8 million shares
held by the Unocal subsidiary. The Company realized proceeds of $122 million
pre-tax from the sale. The price was $25.75 per share less transaction costs.
The Company recorded a pre-tax gain of approximately $22 million in the current
quarter results related to this sale. The Company expects to sell the remaining
875,000 TBI shares it holds as market conditions allow following a 90-day
lock-up period.
In the second quarter of 2003, the Company sold its Matador Petroleum
Corporation ("Matador") shares for approximately $80 million pre-tax. The
Company recorded a $41 million pre-tax gain from the sale of its interest for
the nine months period of 2003.
5. Impairment of Assets
The Company, as part of its regular assessment and in conjunction with its
assessment of the Gulf of Mexico properties held for sale (see note 12) recorded
pre-tax impairment charges of $86 million, or $54 million after-tax, in the nine
months period of 2003. Pre-tax impairments of approximately $79 million were
related to oil and gas fields in the Gulf of Mexico region. In addition, the
Company recorded impairments of approximately $5 million pre-tax relating to the
Trans-Andean oil pipeline, which transports crude oil from Argentina to Chile
and $2 million for pipeline assets associated with producing exploration and
production properties held for sale in the Gulf of Mexico. The Company's
interests in petroleum pipelines are part of the Midstream segment.
In the nine months period of 2002, the Company recorded pre-tax impairment
charges of $27 million, or $17 million after-tax. Impairments of $23 million
pre-tax were primarily related to oil and gas fields in Alaska and the Gulf of
Mexico region. The Company also recorded a pre-tax impairment charge of $4
million due to a U.S. pipeline company, in which the Company owns an equity
interest.
6. Restructuring
In June 2003, the Company accrued a $27 million pre-tax restructuring charge and
adopted a plan for streamlining the organizational structures in order to align
them with the Company's portfolio requirements and business needs. In the third
quarter of 2003, the Company accrued an additional $10 million pre-tax
restructuring charge to reflect continued streamlining of the organizational
structures. The charge is included in selling, administrative and general
expense on the consolidated earnings statement. The following table reflects the
2003 restructuring activity by quarter:
----------------------- ----------------- ----------- ------------ -------------
Millions of dollars # Employees added Training / Post-
(except employees) to restructuring Termination Outplacement retirement
plan Costs Costs Benefit Costs
----------------------- ----------------- ----------- ------------ -------------
1st Quarter Accrual - - - -
----------------------- ----------------- ----------- ------------ -------------
1st Quarter Payments - - -
----------------------- ----------------- ----------- ------------ -------------
Liability at 3/31/2003 - - -
----------------------- ----------------- ----------- ------------ -------------
2nd Quarter Accrual 219 21 2 4
----------------------- ----------------- ----------- ------------ -------------
2nd Quarter Payments - - -
----------------------- ----------------- ----------- ------------ -------------
Liability at 6/30/2003 21 2 4
----------------------- ----------------- ----------- ------------ -------------
3rd Quarter Accrual 127 9 - 1
----------------------- ----------------- ----------- ------------ -------------
3rd Quarter Payments 2 - -
----------------------- ----------------- ----------- ------------ -------------
Liability at 9/30/2003 28 2 5
----------------------- ----------------- ----------- ------------ -------------
The majority of the liabilities are expected to be paid in 2003 and 2004. At
September 30, 2003, 321 of 346 employees had been terminated or had been advised
of planned termination dates as a result of the plan.
-8-
In June 2002, the Company's Gulf Region business unit, which is part of the U.S.
Lower 48 operations in the Exploration and Production segment, adopted a
restructuring plan that resulted in the accrual of a $19 million pre-tax
restructuring charge. The charge included the estimated costs of terminating 202
employees, all of whom were terminated in 2002. At September 30, 2003,
approximately $18 million of the restructuring costs had been paid and charged
against the liability, leaving accrued costs of $1 million on the consolidated
balance sheet. The remaining costs are expected to be paid by the end of 2003.
In November 2002, the Company adopted a restructuring plan that resulted in the
accrual of a $4 million pre-tax restructuring charge related to Exploration and
Production operations in Alaska. The restructuring charge reflected the costs of
terminating 46 employees, of whom 43 had been terminated as of September 30,
2003. At September 30, 2003, approximately $3 million of the restructuring costs
had been paid. The plan will essentially be completed at the end of 2003.
7. Income Taxes
Income taxes on earnings from continuing operations for the third quarter and
nine months periods of 2003 were $147 million and $448 million, respectively,
compared with $68 million and $203 million for the comparable periods of 2002.
The effective income tax rate for the third quarter and nine months periods of
2003 was 49 percent and 45 percent, respectively, compared with 41 percent and
46 percent for the comparable periods of 2002. The higher effective tax rate in
the third quarter of 2003, as compared with the same period a year ago, is due
primarily to currency-related adjustments in Thailand, which was partially
offset by the effect of the mix of positive domestic and foreign earnings in
2003 compared to the mix of domestic losses and foreign earnings in 2002.
Foreign earnings are generally taxed at higher rates. The lower effective tax
rate for the nine months period of 2003, as compared with 2002, reflects the mix
of positive domestic and foreign earnings in 2003 compared to the mix of
domestic losses and foreign earnings in 2002, which was partially offset by the
effect of currency-related adjustments in Thailand and tax adjustments related
to the sale of affiliate investments in 2003. The Company plans to carryforward
the 2002 net operating loss into 2003.
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 third quarters and nine months ended September 30,
2003 and 2002:
--------------------------------------------------------------------------------
Earnings Shares Per Share
Millions except per share amounts (Numerator) (Denominator) Amount
--------------------------------------------------------------------------------
Three months ended September 30, 2003
Earnings from continuing operations $ 152 258.5
Basic EPS $ 0.59
=========
Effect of dilutive securities
Options and common stock equivalents 1.9
---------------------------
152 260.4 $ 0.58
Distributions on subsidiary trust
preferred securities (after-tax) 7 12.3
---------------------------
Diluted EPS $ 159 272.7 $ 0.58
=========
Three months ended September 30, 2002
Earnings from continuing operations $ 99 244.6
Basic EPS $ 0.41
=========
Effect of dilutive securities
Options and common stock equivalents 0.6
---------------------------
Diluted EPS 99 245.2 $ 0.41
=========
Distributions on subsidiary trust
preferred securities (after-tax) 7 12.3
---------------------------
Antidilutive $ 106 257.5 $ 0.41
--------------------------------------------------------------------------------
-9-
Not included in the computation of diluted EPS for the three months ended
September 30, 2003 and 2002, were options outstanding to purchase approximately
8.8 million and 8 million shares, respectively, of common stock. These options
were not included in the computation as the exercise prices were greater than
average market prices of the common shares during the respective quarters.
--------------------------------------------------------------------------------
Earnings Shares Per Share
Millions except per share amounts (Numerator) (Denominator) Amount
--------------------------------------------------------------------------------
Nine months ended September 30, 2003
Earnings from continuing operations $ 538 258.2
Basic EPS $ 2.08
=========
Effect of dilutive securities
Options and common stock equivalents 1.7
---------------------------
538 259.9 $ 2.07
Distributions on subsidiary trust
preferred securities (after-tax) 21 12.3
---------------------------
Diluted EPS $ 559 272.2 $ 2.05
=========
Nine months ended September 30, 2002
Earnings from continuing operations $234 244.5
Basic EPS $ 0.96
=========
Effect of dilutive securities
Options and common stock equivalents 0.9
---------------------------
Diluted EPS 234 245.4 $ 0.96
=========
Distributions on subsidiary trust
preferred securities (after-tax) 20 12.3
---------------------------
Antidilutive $ 254 257.7 $ 0.99
--------------------------------------------------------------------------------
Not included in the computation of diluted EPS for the nine months ended
September 30, 2003 and 2002, were options outstanding to purchase approximately
9 million and 5.8 million shares, respectively, of common stock. These options
were not included in the computation as the exercise prices were greater than
average market prices of the common shares during the respective periods.
Basic and diluted earnings per common share for discontinued operations were as
follows:
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
--------------------------------------------------------------------------------
Millions except per share amounts 2003 2002 2003 2002
--------------------------------------------------------------------------------
Basic earnings per share of common stock:
Discontinued operations:
Earnings from discontinued operations $ - $ - $ 8 $ 1
Weighted average common shares outstanding 258.5 244.6 258.2 244.5
Earnings from discontinued operations $ - $ - 0.03 $ -
Dilutive earnings per share of common stock:
Discontinued operations:
Earnings from discontinued operations $ - $ - $ 8 $ 1
Weighted average common shares outstanding 272.7 245.2 272.2 245.4
Earnings from discontinued operations $ - $ - $ 0.03 $ -
--------------------------------------------------------------------------------
-10-
9. Stock-Based Compensation
Prior to 2003, the Company applied APB Opinion No. 25, "Accounting for Stock
Issued to Employees," and related interpretations in accounting for stock-based
compensation. Before 2003, stock-based compensation expense recognized in the
Company's consolidated earnings included expenses related to the Company's
various cash incentive plans that are paid to certain employees based upon
defined measures of the Company's common stock price performance and total
shareholder return. In addition, the amounts also included expenses related to
the Company's Pure Resources, Inc. ("Pure") subsidiary, which had its own
stock-based compensation plans. Under 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, the Company 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 2003 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 Nine Months
Ended September 30, Ended September 30,
--------------------------------------------------------------------------------
Millions except per share amounts 2003 2002 2003 2002
--------------------------------------------------------------------------------
Net earnings
As reported $ 152 $ 99 $ 463 $ 235
Add: Stock-based employee compensation
expense included in reported net
income, net of related tax effects
and minority interests 4 7 10 15
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 (5) (13) (15) (32)
------------------------------------
Pro forma net earnings $ 151 $ 93 $ 458 $ 218
====================================
Net earnings per share:
Basic - as reported $ 0.59 $ 0.41 $ 1.79 $ 0.96
Basic - pro forma $ 0.58 $ 0.38 $ 1.78 $ 0.89
Diluted - as reported $ 0.58 $ 0.41 $ 1.78 $ 0.96
Diluted - pro forma $ 0.58 $ 0.38 $ 1.76 $ 0.89
10. Comprehensive Income
The Company's comprehensive income was:
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
--------------------------------------------------------------------------------
Millions of dollars 2003 2002 2003 2002
--------------------------------------------------------------------------------
Net earnings $ 152 $ 99 $ 463 $ 235
Change in unrealized holding gain
on investments (a) 8 - 8 -
Change in unrealized gain (loss)
on hedging instruments (b) 17 (26) 14 (35)
Reclassification adjustment for
settled hedging contracts (c) 5 - 16 (1)
Unrealized pension liability adjustments (d) (21) - (21) -
Unrealized foreign currency
translation adjustments 2 (55) 116 (23)
--------------------------------------------------------------------------------
Total comprehensive income $ 163 $ 18 $ 596 $ 176
================================================================================
(a) Net of tax effect of: 5 - 5 -
(b) Net of tax effect of: 10 (15) 8 (21)
(c) Net of tax effect of: 3 - 9 -
(d) Net of tax effect of: 12 - 12 -
-11-
11. Cash and Cash Equivalents
At September 30, At December 31,
------------------------------------
Millions of dollars 2003 2002
--------------------------------------------------------------------------------
Cash $ 240 $ 58
Time deposits 130 110
Marketable securities 115 -
--------------------------------------------------------------------------------
Cash and cash equivalents $ 485 $ 168
================================================================================
The marketable securities at September 30, 2003 reflect the Company's short-term
investment in a money market fund which invests in U.S. Treasury and other U.S.
government agency obligations plus high quality bonds and commercial paper
obligations of domestic corporations. The fund is rated "AAA" by Moody's
Investors Service, Inc. and Standard & Poor's Ratings Services.
12. Assets Held for Sale
The Company initiated a divestiture program in June 2003 that will involve
approximately 100 fields in the Gulf of Mexico shelf and onshore, including
associated pipelines. In the third quarter of 2003, the Company reached an
agreement with Forest Oil Corporation ("Forest") for the sale of 70 properties.
The sale of the majority of the 70 properties to Forest was completed in the
fourth quarter of 2003 (see note 21). The Company expects to sell the rest of
the properties by year-end. The Company has marked the assets to market at
September 30, 2003, and does not anticipate material gains or losses upon the
closing of the sales in the fourth quarter of 2003.
The Company's Unocal North Sumatra Geothermal, Ltd. subsidiary has agreed to
sell its rights and interest in the Sarulla geothermal project on the island of
Sumatra, Indonesia to the Indonesian state electricity company. The anticipated
sales price is $60 million. The transaction is expected to close in the fourth
quarter of 2003, and the Company expects to record an after-tax gain of
approximately $15 million on the transaction.
The Company is in the process of selling its interests in the Trans-Andean oil
pipeline, which transports crude oil from Argentina to Chile. The anticipated
sales price is approximately $38 million. The transaction is expected to close
early 2004, and the Company recorded a pre-tax impairment on the transaction of
approximately $5 million in the third quarter of 2003.
Details of the assets and liabilities for the assets classified as held for
sale, as of September 30, 2003, are presented below:
Millions of dollars U.S. Lower 48 Midstream Geothermal Total
--------------------------------------------------------------------------------
Assets
Properties - net $ 305 $ 6 $ 26 $ 337
Other assets 6 38 - 44
--------------------------------------------------------------------------------
Total assets $ 311 $ 44 $ 26 $ 381
================================================================================
Liabilities
Accrued abandonment, restoration
and environmental liabilities $ 90 $ - $ - $ 90
Other deferred credits
and liabilities 7 - - 7
--------------------------------------------------------------------------------
Total liabilities $ 97 $ - $ - $ 97
================================================================================
-12-
13. Postemployment Benefit Plans
The Company has numerous plans worldwide that provide eligible employees with
retirement benefits. The Company also has medical plans that provide health care
benefits for eligible employees and many of its retired employees.
The Company's 2003 restructuring plan and the sale of producing properties in
the Gulf of Mexico region resulted in the termination of a significant number of
employees (see note 6). As a result, the Company recognized $5 million in
curtailment costs related to its Qualified Retirement and Post Retirement
Welfare plans covering current and former U.S. payroll employees. This charge is
reflected as a component of administrative and general expense in the
consolidated income statement. As a result of these terminations the Company was
required to remeasure these postretirement benefit obligations as of September
30, 2003 and the cost of these plans for the full year 2003.
In the third quarter of 2003 the Company recognized an additional $25 million in
minimum pension liability as a result of the remeasurement of the obligations
and assets of the Qualified Retirement Plan at September 30, 2003. The
recognition of this additional liability resulted in an $8 million reduction in
the intangible asset for unrecognized prior years' service costs and a pre-tax
charge of $33 million ($21 million after-tax) to the other comprehensive income
component of stockholders' equity.
The assumed rates to measure the benefit obligations, expected returns on assets
and expense for the Qualified Retirement and Post Retirement Welfare plans were:
Pension Benefits Other Benefits
--------------------------------------------------------------------------------
1st-3rd Qtr. 4th Qtr. 1st-3rd Qtr. 4th Qtr.
Rate assumptions 2003 2003 2003 2003
--------------------------------------------------------------------------------
Discount rates 6.75% 6.00% 6.75% 6.00%
Rates of salary increases 5.00% 5.00% 5.00% 5.00%
Expected returns on plan assets 8.50% 8.50% N/A N/A
The remeasurement will not have a material impact on pension related expenses
for the full year 2003 as the increase in the interest cost component triggered
by utilizing a lower discount rate at September 30 was offset by lower service
cost as a result of the curtailments.
14. Long Term Debt and Credit Agreements
During the first nine months of 2003, the Company's consolidated debt, including
the current portion, increased by $109 million. The Company retired $89 million
in 9.25% debentures and paid down $11 million of medium-term notes which
matured. The Company also repurchased $15 million of the $200 million
outstanding balance in 6.375% notes due in 2004, $10 million of the $350 million
outstanding balance in 7.35% notes due in 2009 and repaid $20 million of 6.20%
Industrial Development Revenue Bonds.
In 1999, the Company contributed fixed-price overriding royalty interests from
its working interest shares in certain oil and gas producing properties in the
Gulf of Mexico to Spirit LP. In exchange for its overriding royalty
contributions, valued at $304 million, the Company received an initial general
partnership interest in Spirit LP of approximately 55 percent. An unaffiliated
investor contributed $250 million in cash to the partnership in exchange for an
initial limited partnership interest of approximately 45 percent. In June, 2003
the Company entered into an agreement to pay the limited partner for its
minority interest in Spirit LP, the amount of which was $252 million. In July,
2003 the agreement was executed and the payment was made. In the third quarter
of 2003, FASB Interpretation No. 46 would have required the Company to
consolidate the limited partner, an unaffiliated investor, which would have
resulted in a reclassification of $242 million of minority interests to
long-term debt.
-13-
These decreases in debt and other financings were partially offset by $154
million drawn under the Overseas Private Investment Corporation ("OPIC")
Financing Agreement for the first phase of the West Seno project in Indonesia.
The Company and its co-venturer completed financing arrangements for a portion
of the total costs of the project through two loans arranged with OPIC. One loan
is for $300 million and covers the first phase, and the other loan is for $50
million and is for the second phase. The second phase loan will be subject to
further due diligence by the lender. The initial draw down of $79 million in
April 2003 has a floating rate that is adjusted weekly, which as of September
30, 2003 was set at 1.06%. The remaining $75 million drawn down is fixed at a
rate of 2.41%.
Effective in the third quarter of 2003, FASB Interpretation No. 46 (see note 2
for further details) required the Company to consolidate assets and liabilities
and results of operations of Dayabumi Salak Pratama, Ltd. ("DSPL"), resulting in
the recording of an additional $78 million as long-term debt on the consolidated
balance sheet at September 30, 2003.
At September 30, 2003, the 3-year $295 million Canadian dollar-denominated
non-revolving credit facility was unchanged; however due to increasing strength
of the Canadian dollar, borrowings under the credit facility translated to $216
million, using applicable foreign exchange rates, or a $30 million increase from
year-end 2002.
15. Variable Interest Entities
DSPL is a variable interest entity formed for the purpose of building and
operating a geothermal energy fueled power generating facility in Indonesia.
Under a long-term electricity sales contract, DSPL provides power to the
Indonesian state-owned electricity company, PT. PLN (Persero) ("PLN"). Unocal
Geothermal of Indonesia, Ltd. ("UGI") owns a 50 percent interest in DSPL and is
under contract to administer DSPL operations. DSPL has no employees of its own.
DSPL had loans and notes payable totaling $78 million at September 30, 2003.
Neither UGI nor the Company has guaranteed DSPL's debt obligations, which are
non-recourse. Effective in the third quarter of 2003, FASB Interpretation No. 46
(see note 2 for further details) required the Company to consolidate DSPL,
resulting in the reporting of an additional $78 million as long-term debt on the
consolidated balance sheet at September 30, 2003.
16. Accrued Abandonment, Restoration and Environmental Liabilities
Effective January 1, 2003, the Company adopted SFAS No. 143 which increased its
accrued abandonment and restoration liabilities by $268 million (see note 2 for
further detail). At January 1, 2003 and September 30, 2003, the Company had
accrued $758 million and $791 million, respectively, in estimated abandonment
and restoration costs as liabilities. The increase in the liability account from
January 1, 2003 was due to accrued pre-tax accretion expense of $33 million.
Abandonment liability settlements totaled $13 million during the first nine
months of 2003 and were offset by $13 million in new abandonment liabilities
recorded during the period. There were no material revisions to existing
abandonment and restoration liabilities during the first nine months of 2003.
The Company's total accrued abandonment and restoration liabilities of $791
million at September 30, 2003, include $90 million in abandonment liabilities
associated with assets held for sale (see note 12 for further detail). The
September 30, 2003 liability amount represented approximately one-half of the
Company's determinable abandonment and restoration costs adjusted for inflation.
The Company's reserve for environmental remediation obligations at September 30,
2003 totaled $265 million, of which $144 million was included in current
liabilities. This compared with $245 million at December 31, 2002, of which $113
million was included in current liabilities.
-14-
17. Commitments and Contingencies
The Company has contingent liabilities with respect to material existing or
potential claims, lawsuits and other proceedings, including those involving
environmental, tax, guarantees and other matters, certain of which are discussed
more specifically below. The Company accrues liabilities when it is probable
that future costs will be incurred and such costs can be reasonably estimated.
Such accruals are based on developments to date, the Company's estimates of the
outcomes of these matters and its 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 the Company's future results of operations and financial
condition or liquidity.
Environmental matters
The Company continues to move forward to address environmental issues for which
it is responsible. The Company, in cooperation with regulatory agencies and
others, follows procedures that it has established to identify and cleanup
contamination associated with its past operations. The Company is 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 the Company or others and are associated
with past and present operations, including sites at which the Company has 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
the Company is able to determine whether it is 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 the Company's 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 the Company is usually just one of a number of companies
identified as a PRP, or other reasons.
As disclosed in note 16, at September 30, 2003, the Company had accrued $265
million for estimated future environmental assessment and remediation costs at
various sites where liabilities for such costs are probable and reasonably
estimable. The Company may also incur additional liabilities in the future at
sites where remediation liabilities are probable but future environmental costs
are not presently reasonably estimable because the sites have not been assessed
or the assessments have not advanced to the stage where costs are reasonably
estimable. At those sites where investigations or feasibility studies have
advanced to the stage of analyzing feasible alternative remedies and/or ranges
of costs, the Company estimates that it 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 identified by the Company 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 the Company is 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 may change in the near term,
and in some cases could change substantially, 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.
-15-
The accrued costs and the possible additional costs are shown below for four
categories of sites:
At September 30, 2003
----------------------------
Possible
Additional
Millions of dollars Reserve Costs
--------------------------------------------------------------------------------
Superfund and similar sites $ 16 $ 15
Active Company facilities 32 30
Company facilities sold with retained liabilities
and former Company-operated sites 99 80
Inactive or closed Company facilities 118 85
--------------------------------------------------------------------------------
Total $ 265 $ 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 the Company has a contractual agreement to pay a share of the
remediation costs. For these sites, the Company generally has less control over
the timing of the work and consequently the timing of the associated payments.
Based on available information, the Company estimates that the majority of the
amounts included in the reserve will be paid within the next three to five
years.
At the sites where the Company has contractual agreements to share remediation
costs with third parties, the reserve reflects the Company's 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 the Company sold
facilities or a business to a third party, sharing of remediation costs for
those sites may be included in the sales agreement.
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 the Company
may be one. The Company has been notified that it is a PRP at the sites included
in this category. At the sites where the Company has not denied liability, the
Company's contribution to the contamination at these sites was primarily from
operations identified below.
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.
The "Company facilities sold with retained liabilities and former
Company-operated sites" and "Inactive or closed Company facilities" categories
include former Company 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 these categories are former oil and gas fields that the Company no
longer operates. 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, agricultural chemical retail
businesses and ferromolybdenum production operations.
-16-
Superfund and similar sites - Included in this category of sites are:
o The McColl site in Fullerton, California
o The Operating Industries site in Monterey Park, California
o The Casmalia Waste site in Casmalia, California
At September 30, 2003, Unocal had received notifications from the U.S.
Environmental Protection Agency ("EPA") that the Company may be a PRP at 22
sites and may share certain liabilities at these sites. Of the total, four sites
are under investigation and/or litigation and the Company's potential liability
is not presently determinable and for one site, the Company has denied
responsibility. At one site the Company's potential liability appears to be de
minimis. Of the remaining 16 sites, where the Company has concluded that
liability is probable and to the extent costs can be reasonably estimated, a
reserve of $12 million has been established for future remediation and
settlement costs.
Various state agencies and private parties had identified 18 other similar PRP
sites. Four sites are under investigation and/or litigation and the Company's
potential liability is not presently determinable and at three sites the
Company's potential liability appears to be de minimis. Where the Company has
concluded that liability is probable and to the extent costs can be reasonably
estimated at the remaining 11 sites, a reserve of $4 million has been
established for future remediation and settlement costs.
The sites discussed above exclude 125 sites where the Company's liability has
been settled, or where the Company has 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.
The Company does not consider the number of sites for which it has been named a
PRP as a relevant measure of liability. Although the liability of a PRP is
generally joint and several, the Company is usually just one of numerous
companies designated as a PRP. The Company's 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 the Company's ultimate costs.
Active Company facilities - 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
The Company has 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.
The Company recorded provisions of $8 million during the first nine months of
2003 for the "Active Company facilities" category of sites. The provisions were
primarily for the remedial investigation and feasibility study (RI/FS) being
performed at a molybdenum mine located in Questa, New Mexico, that is owned by
the Company's Molycorp, Inc. ("Molycorp") subsidiary. Molycorp has been working
closely with the U.S. Environmental Protection Agency and the State of New
Mexico in conducting the RI/FS at the mine during the year. The RI/FS is being
performed to determine if past mining operations have had an adverse impact on
the environment. Numerous additions and changes to the RI/FS scope have been
required by the agencies, which will require a higher level of effort than
originally projected.
The Company made payments of $9 million for this category of sites in the
first nine months of 2003.
Company facilities sold with retained liabilities and former Company-operated
sites - Company facilities sold with retained liabilities include:
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.
-17-
In each sale, the Company retained a contractual remediation or indemnification
obligation and is 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 the
Company retained certain levels of remediation liabilities; and/or identified in
subsequent claims made by buyers of the properties. Former Company-operated
sites include service stations, distribution facilities and oil and gas fields
that were previously operated but not owned by the Company.
The Company has an aggregate reserve of $99 million for this group of sites.
During the first nine months of 2003, provisions of $27 million for the "Company
facilities sold with retained liabilities and former Company-operated sites"
category were recorded. These provisions included the estimated cleanup costs
for oil fields located in Michigan and California that were formerly operated by
the Company. The estimated costs are based on assessments recently performed at
the sites, higher than anticipated volumes of contaminated soil at existing
sites and higher remediation costs for soil excavation and disposal than
originally anticipated.
The provisions for this category of sites were also the result of revised
remediation cost estimates that were identified during the first and second
quarters of 2003 for former service station sites.
Payments of $32 million were made during the first nine months of 2003 for sites
in this category.
Inactive or closed Company facilities - The major sites 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 $118 million has been established for these types of facilities.
During the first nine months of 2003, the Company accrued $42 million related to
sites in this category primarily for the Guadalupe oil field and for remediation
projects at the Beaumont Refinery. For the Guadalupe oil field site, it was
determined that contaminated soil excavated from the site will probably be taken
to an offsite landfill for disposal. The soil is contaminated with diluent, a
kerosene-like additive used in the field's former operations. Previously, the
Company had planned to remediate the soil on-site; however, a preliminary draft
report for the ecological risk study being conducted indicates that on-site
remediation is not viable. The provisions recorded for the site include the
costs for the offsite disposal alternative. The provisions recorded for the
Guadalupe oil field also include estimated costs for remediation work that is
ongoing at the site. This work includes groundwater monitoring, operation and
maintenance of remedial systems, restoration, site assessment and regulatory
agency oversight and permitting procedures. The provisions for these costs are
based on data from various studies and assessments that have been completed for
the site in conjunction with data provided by the project management system the
Company has in place.
A provision was also recorded for the Company's former Beaumont, Texas refinery.
The Company has been working with the Texas Commission on Environmental Quality
("TCEQ") to develop plans for closing impoundments used in the site's former
operations and for other remediation projects. In the first nine months of 2003,
the Company recorded a provision for the revised estimated costs of the
impoundment closure plan based on the TCEQ initial draft permit that was issued
for the site.
Payments of $11 million were made during the first nine months of 2003 for sites
in this category.
The Company is 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, the Company is 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 the Company's facility in
Beaumont, Texas, a former agricultural chemical facility in Corcoran,
California, and Molycorp's facility in Washington, Pennsylvania. 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.
-18-
The Company also must provide financial assurance for future closure and
post-closure costs of its RCRA-permitted facilities and for decommissioning
costs at facilities that are under radioactive source materials licenses.
Pursuant to a 1998 settlement agreement between the Company and the State of
California (and the subsequent stipulated judgment entered by the Superior
Court), the Company must provide financial assurance for anticipated costs of
remediation activities at its inactive Guadalupe oil field. Also, pursuant to a
1995 settlement agreement between Molycorp and the California Department of
Toxic Substances Control (and subsequent final judgment entered by the Superior
Court), the Company must provide financial assurance for anticipated costs of
disposing of certain wastes, as well as closing facilities associated with the
handling of those wastes, at Molycorp's Mountain Pass, California, facility. At
September 30, 2003, amounts in the remediation reserve for these facilities
totaled $121 million, as included in the previously discussed "Active Company
facilities" and "Inactive or closed Company facilities" categories. At those
sites where investigations or feasibility studies have advanced to the stage of
analyzing alternative remedies and/or ranges of costs, the Company estimates
that it could 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, the Company believes that
these obligations could have a material adverse effect on the Company's results
of operations but are not expected to be material to the Company's consolidated
financial condition or liquidity.
The total environmental remediation reserve recorded on the consolidated balance
sheet represents the Company's estimates of assessment and remediation costs
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. The reserve 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, amounts reserved may change substantially in the
near term.
The Company maintains 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 the Company's contingent legal exposures enumerated
above are uninsurable either due to insurance policy limitations, public policy
or market conditions, management believes that its current insurance program
significantly reduces the possibility of an incident causing a material adverse
financial impact to the Company.
-19-
Certain Litigation and Claims
City of Santa Monica MTBE Lawsuit: In 2000, the City of Santa Monica, California
(the "City") sued Shell Oil Company and other oil companies, including the
Company, for contamination with methyl tertiary butyl ether ("MTBE") and a
related chemical, tertiary butyl alcohol ("TBA"), of water pumped from the
City's Charnock wellfield (City of Santa Monica v. Shell Oil Company et al.
California Superior Court, Orange County, Case No. 01CC04331). The City alleges
that releases from sites owned by Shell, ChevronTexaco Corporation and
ExxonMobil Corporation caused the wellfield to be shut down, that releases from
sites owned by Unocal subsequently impacted the wellfield. The City also alleges
Unocal is liable under a products liability theory for gasoline it manufactured
or sold that was ultimately distributed to area facilities operated by others.
The Company is also subject to potential contractual liability for contamination
from former facilities related to our gasoline marketing business sold in 1997.
In 2001, Shell filed a cross-complaint against the Company and other oil
companies, seeking the recovery of the funds it has expended to respond to the
contamination.
Several of the defendants other than the Company have entered into settlement
agreements with the City, which are subject to court approval. The Company's
current analysis does not indicate any such liabilities are likely to be
significant.
Based on a rigorous technical analysis of the data, the Company believes it has
strong defenses to the allegations in the complaint applicable to both its
former operations and facilities and the product liability claims, including the
lack of evidence that its former service stations or activities are responsible
for any contamination that has reached or threatens the wellfield. Subject to a
lifting of a current stay of discovery due to ongoing settlement discussions
among the parties the Company intends to request completion of limited discovery
previously stayed that may support filing of appropriate motions for summary
adjudication on the City's most significant claims.
For several years prior to the City's suit, the EPA and the California Regional
Water Quality Control Board have asserted jurisdiction over contamination of
groundwater potentially affecting the wellfield, and these agencies have issued
a number of orders under RCRA and state law to the Shell defendants and the
other defendant oil companies, including the Company, with respect to both
investigation of individual facilities and regional contamination, and requiring
replacement of water lost to the City, which Shell is currently providing. In
January 2003, the EPA Regional Administrator for Region IX wrote to the settling
parties advising that it intended to issue a unilateral order to all parties
whose releases have been demonstrated to contribute to contamination in the
Charnock Sub-Basin ordering cleanup of MTBE and TBA "hot spots," unless a
settlement in principle among all concerned parties was reached by June 30,
2003. The Company has submitted to these agencies several technical analyses,
which it believes demonstrate that its sites are not a part of any regional
contamination problem, but, rather, present, at the most, localized issues which
the Company, under agency oversight, has been successfully resolving. The
Company met with senior EPA and Water Board Officials in May 2003 to discuss
these issues, and the EPA has so far taken no action on its January 2003 letter,
but continues to assert potential enforcement options if overall settlements are
not reached.
Agrium Litigation: In June 2002, a lawsuit was filed against the Company 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, the Company 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"). The Company 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 has since remanded the Agrium Claim to
the California Superior Court. In addition, the Company has initiated
arbitration concerning the Gas Purchase and Sale Agreement ("GPSA") between the
Company and Agrium U.S. Inc. (AAA Case No. 70 198 00539 02) (the "Arbitration").
-20-
The Agrium Claim alleges numerous causes of action relating to Agrium's purchase
from the Company of a nitrogen-based fertilizer plant on the Kenai Peninsula,
Alaska, in September 2000. The primary allegations involve the Company's
obligation to supply natural gas to the plant pursuant to the GPSA. Agrium
alleges that the Company misrepresented the amount of natural gas reserves
available for sale to the plant as of the closing of the transaction and that
the Company has failed to develop additional natural gas reserves for sale to
the plant. Agrium also alleges that the Company 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 the Company in operating
and managing certain oil and gas leases and other facilities. Agrium also seeks
declaratory relief concerning the base price of gas under the GPSA, as well as
for the calculation of payments under a "Retained Earnout" covenant that
entitles the Company 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 the
Company 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 the Company Claim, the Company seeks declaratory relief in its 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 is also seeking over $600,000 in reliability bonuses due under the
GSA and 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 agreement for the sale of the plant (the "PSA") contains a limit
on damages of $50 million. The Company believes it has a meritorious defense to
each of the Agrium claims, but that in any event its exposure to damages for all
disputes is limited by the agreements. Agrium alleges that it is entitled to
recover damages in excess of those amounts.
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
are scheduled to commence May 24, 2004. Discovery is now proceeding.
Bangladesh Moulavi Bazar #1 Claims: In July 2002, the Company's 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. The Company 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 contractors' operations. Even if some form of
compensation were due, the Company 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 the Company's Unocal Bangladesh, Ltd., subsidiary ("Unocal Bangladesh"))
of entitlement to the recovery of costs incurred in 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 deemed commercial, from other commercial fields in the
Moulavi Bazar "ring-fenced" area of Block 14. Consequently, the Company and OBL
consider the matter closed and Unocal Blocks 13 and 14 Ltd. has advised
Petrobangla that no additional compensation is warranted.
-21-
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. The Company was notified of the suit on May 26, 2003 when it 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 the Company believes the action is not well
founded.
Nuevo Energy Claim: In March 2003, the Company received a letter from Nuevo
Energy Company regarding a contingent payment for the year 2002 owed by Nuevo to
the Company under the terms of the 1996 Asset Purchase Agreement pursuant to
which Nuevo purchased substantially all of the Company's operating California
oil and gas properties. Notwithstanding that Nuevo had notified the Company in
January 2003 of its estimate of the payment for 2002, Nuevo now claims that the
long-standing calculation methodology for this payment was incorrect, that no
payment should be due for 2002, and that the payment made for 2001 should be
refunded. The Company disputes Nuevo's new position. The current disputed cash
exposure to the Company is $27 million.
On June 30, 2003, Nuevo filed suit against Unocal in the U.S. District Court for
the Central District of California, Case No. 03-4664 (RCx). Nuevo seeks $10.8
million, the amount Nuevo alleges it paid Unocal in error. Nuevo also seeks a
declaratory judgment regarding its right to take deductions in calculating the
contingent payment in the future. Unocal has counterclaimed, seeking in excess
of $16 million for amounts currently owed under the contingent payment agreement
and for a declaratory judgment regarding the rights and relations of Unocal and
Nuevo under that agreement.
In view of the inherent difficulty of predicting the outcome of legal matters,
the Company cannot state with confidence what the eventual outcome of the four
preceding matters will be. However, based on current knowledge, none of the
preceding matters is presently expected to have a material adverse effect on the
Company's consolidated financial condition or liquidity, but each of them could
have a material adverse effect on the Company's results of operations for the
accounting period or periods in which one or more of them might be resolved
adversely.
Tax matters
The Company believes it has adequately provided in its accounts for tax items
and issues not yet resolved. Several prior material tax issues are unresolved.
Resolution of these tax issues impact not only the year in which the items
arose, but also the Company's tax situation in other tax years. With respect to
1979-1984 taxable years, all issues raised for these years have now been
settled, with the exception of the effect of the carryback of a 1993 net
operating loss ("NOL") to tax year 1984 and resultant credit adjustments. The
1985-1990 taxable years are before the Appeals division of the Internal Revenue
Service. All issues raised with respect to those years have now been settled,
with the exception of the effect of the 1993 NOL carryback and resultant
adjustments. The Joint Committee on Taxation of the U.S. Congress has reviewed
the settled issues with respect to 1979-1990 taxable years and no additional
issues have been raised. While all tax issues for the 1979-1990 taxable years
have been agreed and reviewed by the Joint Committee, these taxable years will
remain open due to the 1993 NOL carryback. The 1993 NOL results from certain
specified liability losses, which occurred during 1993, and which resulted in a
tax refund of $73 million. Consequently, these tax years will remain open until
the specified liability loss, which gave rise to the 1993 NOL, is finally
determined by the Internal Revenue Service and is either agreed to with the IRS
or otherwise concluded in the Tax Court proceeding. In 1999, the United States
Tax Court granted Unocal's motion to amend the pleadings in its Tax Court cases
to place the 1993 NOL carryback in issue. The 1991-1994 taxable years are now
before the Appeals division of the Internal Revenue Service. The 1995-1997
taxable years are before the Appeals division of the Internal Revenue Service.
The 1998-2001 taxable years are now under examination by the Internal Revenue
Service.
-22-
Guarantees Related to Assets or Obligations of Third Parties
The Company has 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 the Company either leased property from or sold
property to these third parties. The properties may or may not have been
contaminated by various Company operations. Where it has been or will be
determined that the Company is responsible for contamination, the guarantees
require the Company 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 the Company 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.
The Company has 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 the Company's reserve for
environmental remediation obligations. At September 30, 2003, the reserve for
this category totaled $99 million. For those sites where investigations or
feasibility studies have advanced to the stage of analyzing feasible alternative
remedies and/or ranges of costs, the Company estimates that it could incur
possible additional remediation costs aggregating approximately $80 million. See
the discussion elsewhere in this footnote for additional information regarding
this category.
The Company has guaranteed the debt of certain joint ventures accounted for by
the equity method. The majority of this debt matures evenly through the year
2014. The maximum potential amount of future payments the Company could be
required to make is approximately $20 million.
In the ordinary course of business, the Company has agreed to indemnify cash
deficiencies for certain domestic pipeline joint ventures, which the Company
accounts for on the equity method. These guarantees are considered in the
Company's 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, the Company believes the payments
would not have a material adverse impact on its financial condition or
liquidity.
-23-
Financial Assurance for Unocal Obligations
In the normal course of business, the Company has performance obligations which
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 the Company if drawn upon. At September 30, 2003,
the Company had obtained various surety bonds for approximately $196 million.
These surety bonds included a bond for $83 million securing the Company's
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 approximately $113 million in various
other routine performance bonds held by local, city, state and federal agencies.
The Company also had obtained approximately $46 million in standby letters of
credit at September 30, 2003, of which $17 million represented additional
collateral related to the aforementioned fixed price natural gas sales contract.
The Company has entered into indemnification obligations in favor of the
providers of these surety bonds and letters of credit.
The Company has various other guarantees for approximately $553 million.
Approximately $134 million of the $553 million in guarantees represent financial
assurance given by the Company on behalf of its Molycorp subsidiary relating to
permits covering operations and discharges from its Questa, New Mexico,
molybdenum mine. The Company's 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 $333 million of the $553 million would require the
Company to obtain a surety bond or a letter of credit or establish a trust fund
if its 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.
Approximately $165 million of the surety bonds, letters of credit and other
guarantees that the Company is required to obtain or issue reflect obligations
that are already included on the consolidated balance sheet in other current
liabilities and other deferred credits. The surety bonds, letters of credit and
other guarantees may also reflect some of the possible additional remediation
liabilities discussed earlier in this note.
Other matters
The Company has a lease agreement relating to its Discoverer Spirit deepwater
drillship, with a remaining term of approximately 24 months at September 30,
2003. The drillship has a current minimum daily rate of approximately $224,000.
The future remaining minimum lease payment obligation was approximately $160
million at September 30, 2003.
The Company also has other contingent liabilities with respect to litigation,
claims and contractual agreements arising in the ordinary course of business. On
the basis of management's assessment of the ultimate amount and timing of
possible adverse outcomes and associated costs, none of such matters is
presently expected to have a material adverse effect on the Company's
consolidated financial condition, liquidity or results of operations.
-24-
18. Financial Instruments and Commodity Hedging
Fair values of debt and other long-term instruments - The estimated fair value
of the Company's long-term debt at September 30, 2003, including the current
portion, was approximately $3.49 billion. The fair value was based on the
discounted amounts of future cash outflows using the rates offered to the
Company for debt with similar remaining maturities.
The estimated fair value of Unocal Capital Trust's 6 1/4 % convertible preferred
securities was approximately $530 million at September 30, 2003. The fair value
was based on the closing trading price of the preferred securities on September
30, 2003.
Commodity hedging activities - The Company uses hydrocarbon derivatives to
mitigate its overall exposure to fluctuations in hydrocarbon commodity prices.
The Company recognized $1 million of gains due to ineffectiveness for cash flow
and fair value hedges in the third quarter and $2 million in gains in the nine
months period ended September 30, 2003. At September 30, 2003, the Company had
approximately $19 million of after-tax deferred gains in accumulated other
comprehensive income on the consolidated balance sheet related to cash flow
hedges for future commodity sales for the period beginning October 2003 through
December 2005. Essentially all of the after-tax gains are expected to be
reclassified to the consolidated earnings statement during the next twelve
months.
Foreign currency contracts - At September 30, 2003, the Company had
approximately $1 million of after-tax deferred gains in accumulated other
comprehensive income on the consolidated balance sheet related to cash flow
hedges for future foreign currency denominated payment obligations through
December 2003. This entire amount is expected to be reclassified to the
consolidated earnings statement during the next twelve months.
Interest rate contracts - The Company enters into interest rate swap contracts
to manage its debt with the objective of minimizing the volatility and magnitude
of the Company's borrowing costs. The Company may also enter into interest rate
option contracts to protect its interest rate positions, depending on market
conditions. At September 30, 2003, the Company had approximately $23 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.
Credit Risk - Financial instruments that potentially subject the Company to
concentrations of credit risks primarily consist of temporary cash investments
and trade receivables. The Company places its temporary cash investments with
high credit quality financial institutions and, by policy, limits the amount of
credit exposure to any one financial institution. The concentration of trade
receivable credit risk is generally limited due to the Company's customers being
spread across industries in several countries. The Company's management has
established certain credit requirements that its customers must meet before
sales credit is extended. The Company monitors the financial condition of its
customers to help ensure collections and to minimize losses.
-25-
19. Supplemental Condensed Consolidating Financial Information
Unocal guarantees all the publicly held securities issued by its 100
percent-owned subsidiaries Unocal Capital Trust and Union Oil. Such guarantees
are full and unconditional and no subsidiaries of Unocal or Union Oil guarantee
these securities.
The following tables present condensed consolidating financial information for
(a) Unocal (Parent), (b) the Trust, (c) Union Oil (Parent) and (d) on a combined
basis, the subsidiaries of Union Oil (non-guarantor subsidiaries). Virtually all
of the Company's operations are conducted by Union Oil and its subsidiaries.
CONDENSED CONSOLIDATED EARNINGS STATEMENT
Three months ended September 30, 2003
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-----------------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ - $ 339 $ 1,313 $ (174) $ 1,478
Interest, dividends and miscellaneous income - 8 (3) - (7) (2)
Gain on sales of assets - - 15 42 8 65
-----------------------------------------------------------------------------------------------------------------------------
Total revenues - 8 351 1,355 (173) 1,541
Costs and other deductions
Purchases, operating and other expenses 4 - 254 817 (164) 911
Depreciation, depletion and amortization - - 61 170 - 231
Impairments - - 14 69 - 83
Dry hole costs - - 5 9 - 14
Interest expense 8 - 38 8 (9) 45
Distributions on convertible preferred securities - 8 - - - 8
-----------------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 12 8 372 1,073 (173) 1,292
Equity in earnings of subsidiaries 161 - 189 - (350) -
Earnings from equity investments - - (1) 55 - 54
-----------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 149 - 167 337 (350) 303
-----------------------------------------------------------------------------------------------------------------------------
Income taxes (3) - 6 144 - 147
Minority interests - - - 4 - 4
-----------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 152 - 161 189 (350) 152
Earnings from discontinued operations - - - - - -
-----------------------------------------------------------------------------------------------------------------------------
Net earnings $ 152 $ - $ 161 $ 189 $ (350) $ 152
=============================================================================================================================
-26-
CONDENSED CONSOLIDATED EARNINGS STATEMENT
Three months ended September 30, 2002
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-----------------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ - $ 310 $ 1,199 $ (210) $ 1,299
Interest, dividends and miscellaneous income 1 8 (68) 65 (9) (3)
Gain on sales of assets - - 1 - - 1
-----------------------------------------------------------------------------------------------------------------------------
Total revenues 1 8 243 1,264 (219) 1,297
Costs and other deductions
Purchases, operating and other expenses 1 - (52) 1,089 (210) 828
Depreciation, depletion and amortization - - 81 164 - 245
Impairments - - 2 4 - 6
Dry hole costs - - 5 35 - 40
Interest expense 8 - 31 9 (8) 40
Distributions on convertible preferred securities - 8 - - - 8
-----------------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 9 8 67 1,301 (218) 1,167
Equity in earnings of subsidiaries 101 - (13) - (88) -
Earnings from equity investments - - 1 34 - 35
-----------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 93 - 164 (3) (89) 165
-----------------------------------------------------------------------------------------------------------------------------
Income taxes (3) - 63 8 - 68
Minority interests - - - 2 (4) (2)
-----------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 96 - 101 (13) (85) 99
Earnings from discontinued operations - - - - - -
Cumulative effects of accounting changes - - - - - -
-----------------------------------------------------------------------------------------------------------------------------
Net earnings $ 96 $ - $ 101 $ (13) $ (85) $ 99
=============================================================================================================================
-27-
CONDENSED CONSOLIDATED EARNINGS STATEMENT
For the nine months ended September 30, 2003
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-------------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ - $ 1,212 $ 4,528 $ (923) $ 4,817
Interest, dividends and miscellaneous income - 25 15 6 (28) 18
Gain on sales of assets - - 49 58 8 115
-------------------------------------------------------------------------------------------------------------------------
Total revenues - 25 1,276 4,592 (943) 4,950
Costs and other deductions
Purchases, operating and other expenses 9 - 877 3,064 (914) 3,036
Depreciation, depletion and amortization - - 245 501 - 746
Impairments - - 17 69 - 86
Dry hole costs - - 63 32 - 95
Interest expense 25 1 97 25 (29) 119
Distributions on convertible preferred securities - 24 - - - 24
-------------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 34 25 1,299 3,691 (943) 4,106
Equity in earnings of subsidiaries 490 - 594 - (1,084) -
Earnings from equity investments - - 6 144 - 150
-------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 456 - 577 1,045 (1,084) 994
-------------------------------------------------------------------------------------------------------------------------
Income taxes (7) - 40 415 - 448
Minority interests - - - 8 - 8
-------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 463 - 537 622 (1,084) 538
Earnings from discontinued operations - - 8 - - 8
Cumulative effects of accounting changes - - (55) (28) - (83)
-------------------------------------------------------------------------------------------------------------------------
Net earnings $ 463 $ - $ 490 $ 594 $ (1,084) $ 463
=========================================================================================================================
-28-
CONDENSED CONSOLIDATED EARNINGS STATEMENT
For the nine months ended September 30, 2002
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-------------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ - $ 805 $ 3,501 $ (611) $ 3,695
Interest, dividends and miscellaneous income 1 25 (61) 80 (28) 17
Gain (loss) on sales of assets - - 15 (13) - 2
-------------------------------------------------------------------------------------------------------------------------
Total revenues 1 25 759 3,568 (639) 3,714
Costs and other deductions
Purchases, operating and other expenses 4 - 434 2,582 (612) 2,408
Depreciation, depletion and amortization - - 261 463 - 724
Impairments - - 23 4 - 27
Dry hole costs - - 22 59 - 81
Interest expense 25 1 109 27 (28) 134
Distributions on convertible preferred securities - 24 - - - 24
-------------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 29 25 849 3,135 (640) 3,398
Equity in earnings of subsidiaries 249 - 313 - (562) -
Earnings from equity investments - - 3 120 - 123
-------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 221 - 226 553 (561) 439
-------------------------------------------------------------------------------------------------------------------------
Income taxes (10) - (23) 236 - 203
Minority interests - - - 5 (3) 2
-------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 231 - 249 312 (558) 234
Earnings from discontinued operations - - - 1 - 1
Cumulative effects of accounting changes - - - - - -
-------------------------------------------------------------------------------------------------------------------------
Net earnings $ 231 $ - $ 249 $ 313 $ (558) $ 235
=========================================================================================================================
-29-
CONDENSED CONSOLIDATED BALANCE SHEET
At September 30, 2003
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-----------------------------------------------------------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ - $ - $ 99 $ 386 $ - $ 485
Accounts and notes receivable - net 71 - 252 770 (84) 1,009
Inventories - - 12 120 - 132
Other current assets - - 122 31 - 153
-----------------------------------------------------------------------------------------------------------------------------
Total current assets 71 - 485 1,307 (84) 1,779
Investments and long-term receivables - net 5,001 - 5,062 828 (9,988) 903
Properties - net - - 2,257 6,238 (3) 8,492
Other assets including goodwill 4 541 172 2,517 (2,698) 536
-----------------------------------------------------------------------------------------------------------------------------
Total assets $5,076 $ 541 $ 7,976 $ 10,890 $ (12,773) $ 11,710
=============================================================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ - $ - $ 299 $ 816 $ (71) $ 1,044
Current portion of long-term debt
and capital leases - - 215 34 - 249
Other current liabilities 51 3 284 360 (14) 684
-----------------------------------------------------------------------------------------------------------------------------
Total current liabilities 51 3 798 1,210 (85) 1,977
Long-term debt and capital leases - - 2,078 790 - 2,868
Deferred income taxes - - (163) 872 - 709
Accrued abandonment, restoration
and environmental liabilities - - 447 465 - 912
Other deferred credits and liabilities 541 - 524 2,546 (2,696) 915
Minority interests - - - 320 (292) 28
Company-obligated mandatorily redeemable
convertible preferred securities of a
subsidiary trust holding solely parent
debentures - 522 - - - 522
Stockholders' equity 4,484 16 4,292 4,687 (9,700) 3,779
-----------------------------------------------------------------------------------------------------------------------------
Total liabilities and stockholders' equity $5,076 $ 541 $ 7,976 $ 10,890 $ (12,773) $ 11,710
=============================================================================================================================
-30-
CONDENSED CONSOLIDATED BALANCE SHEET
At December 31, 2002
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-----------------------------------------------------------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ - $ - $ (18) $ 186 $ - $ 168
Accounts and notes receivable - net 54 - 276 738 (74) 994
Inventories - - 10 87 - 97
Other current assets 1 - 85 30 - 116
-----------------------------------------------------------------------------------------------------------------------------
Total current assets 55 - 353 1,041 (74) 1,375
Investments and long-term receivables - net 4,562 - 4,513 960 (8,991) 1,044
Properties - net - - 2,255 5,624 - 7,879
Other assets including goodwill 3 541 272 (12) (342) 462
-----------------------------------------------------------------------------------------------------------------------------
Total assets $4,620 $ 541 $ 7,393 $ 7,613 $ (9,407) $ 10,760
=============================================================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ - $ - $ 290 $ 788 $ (54) $ 1,024
Current portion of long-term debt
and capital leases - - - 6 - 6
Other current liabilities 44 3 120 455 (20) 602
-----------------------------------------------------------------------------------------------------------------------------
Total current liabilities 44 3 410 1,249 (74) 1,632
Long-term debt and capital leases - - 2,418 584 - 3,002
Deferred income taxes - - (116) 709 - 593
Accrued abandonment, restoration
and environmental liabilities - - 320 302 - 622
Other deferred credits and liabilities 541 - 424 184 (333) 816
Minority interests - - - 313 (38) 275
Company-obligated mandatorily redeemable
convertible preferred securities of a
subsidiary trust holding solely parent debentures - 522 - - - 522
Stockholders' equity 4,035 16 3,937 4,272 (8,962) 3,298
-----------------------------------------------------------------------------------------------------------------------------
Total liabilities and stockholders' equity $4,620 $ 541 $ 7,393 $ 7,613 $ (9,407) $ 10,760
=============================================================================================================================
-31-
CONDENSED CONSOLIDATED CASH FLOWS
For the nine months ended September 30, 2003
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-----------------------------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities $ 140 $ - $ 415 $ 1,098 $ - $1,653
Cash Flows from Investing Activities
Capital expenditures and acquisitions
(includes dry hole costs) - - (336) (960) - (1,296)
Proceeds from sales of assets
and discontinued operations - - 150 204 - 354
-----------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities - - (186) (756) - (942)
-----------------------------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Change in long-term debt and capital leases - - (114) 112 - (2)
Dividends paid on common stock (155) - - - - (155)
Minority interests - - - (257) - (257)
Other 15 - 2 3 - 20
-----------------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities (140) - (112) (142) - (394)
-----------------------------------------------------------------------------------------------------------------------------
Increase in cash and cash equivalents - - 117 200 - 317
-----------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at beginning of period - - (18) 186 - 168
-----------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ - $ - $ 99 $ 386 $ - $ 485
=============================================================================================================================
CONDENSED CONSOLIDATED CASH FLOWS
For the nine months ended September 30, 2002
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-----------------------------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities $ 128 $ - $ 43 $ 1,061 $ - $1,232
Cash Flows from Investing Activities
Capital expenditures and acquisitions
(includes dry hole costs) - - (303) (945) - (1,248)
Proceeds from sales of assets
and discontinued operations - - 23 41 - 64
-----------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities - - (280) (904) - (1,184)
-----------------------------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Change in long-term debt and capital leases - - 284 (114) - 170
Dividends paid on common stock (147) - - - - (147)
Minority interests - - - (6) - (6)
Other 19 - 1 - - 20
-----------------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities (128) - 285 (120) - 37
-----------------------------------------------------------------------------------------------------------------------------
Increase (decrease) in cash and cash equivalents - - 48 37 - 85
-----------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at beginning of period - - 62 128 - 190
-----------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ - $ - $ 110 $ 165 $ - $ 275
=============================================================================================================================
-32-
20. Segment Data
The Company's reportable segments are: Exploration and Production, Trade,
Midstream, and Geothermal and Power Operations. General corporate overhead,
unallocated costs and other miscellaneous operations, including real estate,
carbon and minerals and activities relating to businesses that were sold, are
included under the Corporate and Other heading.
Segment Information Exploration & Production Trade
For the Three Months North America International
ended September 30, 2003
Millions of dollars U.S. Lower 48 Alaska Canada Far East Other
---------------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 147 $ 63 $ 39 $ 317 $ 61 $ 633
Other income (loss) (a) 47 - 12 - 1 (1)
Inter-segment revenues 248 - 36 67 - -
---------------------------------------------------------------------------------------------------------------------------
Total 442 63 87 384 62 632
Earnings from equity investments 6 - - 11 2 1
Earnings (loss) from continuing operations 77 12 15 115 21 3
Earnings from discontinued operations - - - - - -
Cumulative effects of accounting changes - - - - - -
---------------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 77 12 15 115 21 3
---------------------------------------------------------------------------------------------------------------------------
Assets (at September 30, 2003) 3,325 329 1,272 3,085 963 292
---------------------------------------------------------------------------------------------------------------------------
Midstream Geothermal Corporate & Other Total
& Power
Operations Admin Net Interest Environmental
& General Expense & Litigation Other (b)
---------------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 142 $ 41 $ - $ - $ - $ 35 $ 1,478
Other income (loss) (a) 6 2 - (4) - - 63
Inter-segment revenues 2 - - - - (353) -
---------------------------------------------------------------------------------------------------------------------------
Total 150 43 - (4) - (318) 1,541
Earnings from equity investments 17 5 - - - 12 54
Earnings (loss) from continuing operations 16 19 (21) (32) (33) (40) 152
Earnings from discontinued operations - - - - - - -
Cumulative effects of accounting changes - - - - - - -
---------------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 16 19 (21) (32) (33) (40) 152
---------------------------------------------------------------------------------------------------------------------------
Assets (at September 30, 2003) 654 608 - - - 1,182 11,710
---------------------------------------------------------------------------------------------------------------------------
(a) Includes interest, dividends and miscellaneous income, and gain (loss) on sales of assets.
(b) Includes eliminations and consolidation adjustments.
-33-
Segment Information Exploration & Production Trade
For the Three Months North America International
ended September 30, 2002
Millions of dollars U.S. Lower 48 Alaska Canada Far East Other
---------------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 120 $ 64 $ 43 $ 283 $ 39 $ 623
Other income (loss) (a) 2 - (1) - 1 (1)
Inter-segment revenues 210 - - 59 37 -
---------------------------------------------------------------------------------------------------------------------------
Total 332 64 42 342 77 622
Earnings (loss) from equity investments - - - 9 2 1
Earnings (loss) from continuing operations 13 10 (2) 129 7 (1)
Earnings from discontinued operations - - - - - -
---------------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 13 10 (2) 129 7 (1)
---------------------------------------------------------------------------------------------------------------------------
Assets (at December 31, 2002) 3,358 326 1,113 2,861 821 304
---------------------------------------------------------------------------------------------------------------------------
Midstream Geothermal Corporate & Other Total
& Power
Operations Admin Net Interest Environmental
& General Expense & Litigation Other (b)
---------------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 58 $ 28 $ - $ - $ - $ 41 $ 1,299
Other income (loss) (a) 1 (8) - 3 - 1 (2)
Inter-segment revenues 3 - - - - (309) -
---------------------------------------------------------------------------------------------------------------------------
Total 62 20 - 3 - (267) 1,297
Earnings (loss) from equity investments 15 (3) - - - 11 35
Earnings (loss) from continuing operations 17 5 (21) (28) (14) (16) 99
Earnings from discontinued operations - - - - - - -
---------------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 17 5 (21) (28) (14) (16) 99
---------------------------------------------------------------------------------------------------------------------------
Assets (at December 31, 2002) 511 526 - - - 940 10,760
---------------------------------------------------------------------------------------------------------------------------
(a) Includes interest, dividends and miscellaneous income, and gain (loss) on sales of assets.
(b) Includes eliminations and consolidation adjustments.
-34-
Segment Information Exploration & Production Trade
For the Nine Months North America International
ended September 30, 2003
Millions of dollars U.S. Lower 48 Alaska Canada Far East Other
---------------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 449 $191 $134 $ 925 $202 $2,291
Other income (loss) (a) 96 - 12 - 1 (2)
Inter-segment revenues 920 - 115 230 - 1
---------------------------------------------------------------------------------------------------------------------------
Total 1,465 191 261 1,155 203 2,290
Earnings from equity investments 15 - - 30 7 2
Earnings (loss) from continuing operations 277 41 47 352 71 (2)
Earnings from discontinued operations - - - - - -
Cumulative effects of accounting changes (b) 11 (43) 4 13 - -
---------------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 288 (2) 51 365 71 (2)
---------------------------------------------------------------------------------------------------------------------------
Assets (at September 30, 2003) 3,325 329 1,272 3,085 963 292
---------------------------------------------------------------------------------------------------------------------------
Midstream Geothermal Corporate & Other Total
& Power
Operations Admin Net Interest Environmental
& General Expense & Litigation Other (c)
---------------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 411 $104 $ - $ - $ - $110 $ 4,817
Other income (loss) (a) 8 4 - 6 - 8 133
Inter-segment revenues 6 - - - - (1,272) -
---------------------------------------------------------------------------------------------------------------------------
Total 425 108 - 6 - (1,154) 4,950
Earnings from equity investments 49 10 - - - 37 150
Earnings (loss) from continuing operations 52 38 (66) (91) (78) (103) 538
Earnings from discontinued operations - - - - - 8 8
Cumulative effects of accounting changes (b) (2) - - - - (66) (83)
---------------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 50 38 (66) (91) (78) (161) 463
---------------------------------------------------------------------------------------------------------------------------
Assets (at September 30, 2003) 654 608 - - - 1,182 11,710
---------------------------------------------------------------------------------------------------------------------------
(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.
-35-
Segment Information Exploration & Production Trade
For the Nine Months North America International
ended September 30, 2002
Millions of dollars U.S. Lower 48 Alaska Canada Far East Other
---------------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 357 $188 $143 $ 800 $ 99 $1,723
Other income (loss) (a) 6 - (1) - 1 (1)
Inter-segment revenues 610 - - 173 78 1
---------------------------------------------------------------------------------------------------------------------------
Total 973 188 142 973 178 1,723
Earnings (loss) from equity investments - - - 26 6 1
Earnings (loss) from continuing operations 37 ( 1) (5) 332 31 1
Earnings from discontinued operations - - - - - -
---------------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 37 ( 1) (5) 332 31 1
---------------------------------------------------------------------------------------------------------------------------
Assets (at December 31, 2002) 3,358 326 1,113 2,861 821 304
---------------------------------------------------------------------------------------------------------------------------
Midstream Geothermal Corporate & Other Total
& Power
Operations Admin Net Interest Environmental
& General Expense & Litigation Other (b)
---------------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 197 $ 89 $ - $ - $ - $ 99 $ 3,695
Other income (loss) (a) 3 (4) - 11 - 4 19
Inter-segment revenues 9 - - - - (871) -
---------------------------------------------------------------------------------------------------------------------------
Total 209 85 - 11 - (768) 3,714
Earnings (loss) from equity investments 52 (1) - - - 39 123
Earnings (loss) from continuing operations 59 25 (64) (93) (50) (38) 234
Earnings from discontinued operations - - - - - 1 1
---------------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 59 25 (64) (93) (50) (37) 235
---------------------------------------------------------------------------------------------------------------------------
Assets (at December 31, 2002) 511 526 - - - 940 10,760
---------------------------------------------------------------------------------------------------------------------------
(a) Includes interest, dividends and miscellaneous income, and gain (loss) on sales of assets.
(b) Includes eliminations and consolidation adjustments.
-36-
21. Subsequent Events
In October 2003, the Company announced a $300 million tender offer to repurchase
debt securities due in 2005 and 2008. During October, the Company repurchased
$194 million of debt principal through the tender offer at a premium of $21
million, including $115 million of the $200 million 7.20 percent notes due in
2005 and $79 million of the $100 million 6.50 percent notes due in 2008. In
addition, through open market transactions, the Company repurchased an
additional $96 million of various notes due from 2004 through 2009 at a premium
of $12 million with an average interest rate of 6.20 percent, bringing the total
repurchases to $290 million subsequent to September 30, 2003.
In late October and early November 2003, the Company completed the sale of the
majority of the 70 properties held for sale in the Gulf of Mexico and onshore
Louisiana to Forest Oil for net proceeds totaling $218 million. This price
includes adjustments that take into account the July 1, 2003 effective date of
the sale (see notes 5 and 12 for discussions related to these assets).
In addition, the sales of properties with preferential rights still
outstanding are expected to close later in the fourth quarter of 2003.
The Company has marked these assets to market at September 30, 2003, and does
not anticipate material gains or losses upon the closing of the sales.
In late October 2003, the Company completed a property exchange with Apache
Corporation that consolidated both companies' interests in two oil and gas
fields in the Gulf of Mexico region. Under the terms of the exchange, the
Company received Apache's 13 percent working interest in the Unocal-operated
Ship Shoal 208 field and an undisclosed amount of cash in exchange for Unocal's
majority interest in the Lake Pagie field in Terrebone Parish, Louisiana. The
Company now holds 100 percent of the Ship Shoal 208 field, which covers three
Gulf of Mexico blocks. The Company expects to record a pre-tax gain of
approximately $21 million from the transaction in the fourth quarter 2003.
-37-
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
The following discussion and analysis of the consolidated financial condition
and results of operations of the Company should be read in conjunction with
Management's Discussion and Analysis in Item 7 of Unocal's 2002 Annual Report on
Form 10-K.
CONSOLIDATED RESULTS
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
----------------------------------------
Millions of dollars 2003 2002 2003 2002
--------------------------------------------------------------------------------
Earnings from continuing operations $ 152 $ 99 $ 538 $ 234
Earnings from discontinued operations - - 8 1
Cumulative effects of accounting changes - - (83) -
--------------------------------------------------------------------------------
Net earnings $ 152 $ 99 $ 463 $ 235
================================================================================
Continuing Operations
Third Quarter Results: Earnings from continuing operations were $152 million in
the third quarter of 2003, which was an increase of $53 million compared to the
same quarter a year ago, primarily reflecting improved results from the
Company's exploration and production operations due to higher worldwide natural
gas and liquids prices. Higher worldwide commodity prices increased net earnings
by approximately $100 million. The Company's worldwide average realized natural
gas price, with no impact from hedging activities in the current quarter, was
$3.60 per Mcf. This was an increase of 81 cents per Mcf, or 29 percent, from the
$2.79 per Mcf realized during the same period a year ago, which included a gain
of one cent per Mcf from hedging activities. In the current quarter, the
Company's worldwide average realized liquids price was $27.28 per Bbl, which was
an increase of $2.47 per Bbl, or 10 percent, from the same period a year ago.
The Company's hedging program lowered the average realized liquids price by 6
cents per Bbl in the current quarter while the third quarter of the prior year
included a loss of one cent per Bbl from hedging activities. The current quarter
also included gains on asset sales of approximately $30 million after-tax
related to the sale of the Company's shares in Tom Brown, Inc. ("TBI") (see note
4 to the consolidated financial statements in Item 1 of this report) and other
oil and gas properties. Exploration expenses, including dry hole costs, were
approximately $25 million lower in the third quarter of 2003 compared to the
same period a year ago primarily as a result of lower dry hole costs in North
America and lower amortization of exploratory leasehold costs worldwide. The
geothermal and power operations added $14 million in earnings improvement in the
current quarter as compared to the same period a year ago, primarily as a result
of higher steam prices and generation in Indonesia and the impact of foreign
exchange gains on the results from the Company's equity interests in gas-fired
power plants in Thailand. The third quarter of 2002 included an after-tax loss
of $5 million in mark-to-market accruals and realized gains/losses for non-hedge
commodity derivatives recorded by the Company's Northrock Resources Ltd.
("Northrock") subsidiary.
These positive variance factors were partially offset by approximately $50
million in higher after-tax impairments compared to the same period a year ago,
which was primarily related to the assets held for sale. In addition, worldwide
production for the current quarter was 441,000 BOE/d down from 466,000 BOE/d for
the same period a year ago due primarily to lower North America production which
reduced net earnings by approximately $10 million in the current quarter
compared with the same period a year ago. North America liquids production
averaged 80,000 Bbl/d in the current quarter, down from 92,000 Bbl/d in the same
period a year ago, while natural gas production averaged 734 MMcf/d in the
current quarter, down from 867 MMcf/d in the same period a year ago. Most of the
production decline was due to natural declines in existing fields in the Gulf of
Mexico and the divestiture of various properties in Canada, onshore U.S. and the
Gulf of Mexico during the first nine months of 2003. In addition, the Company's
minerals operations contributed approximately $10 million after-tax of lower
earnings in the current quarter as compared to the third quarter of 2002. Higher
pension related expenses also reduced net earnings by approximately $10 million
in the current quarter compared to the same period a year ago.
-38-
The Company's after-tax environmental and litigation expenses were $38 million
in the current quarter of 2003, compared with $25 million in the same period a
year ago, primarily reflecting higher outside litigation support costs. The
current quarter also includes an additional $6 million after-tax charge related
to the Company's 2003 restructuring plan.
Nine Months Results: Earnings from continuing operations were $538 million in
the first nine months of 2003 compared to $234 million for the same period a
year ago. Higher worldwide commodity prices increased net earnings by
approximately $400 million. The Company's worldwide average realized natural gas
price, including a loss of 11 cents per Mcf from hedging activities, was $3.68
per Mcf in the first nine months of 2003. This was an increase of 96 cents per
Mcf, or 35 percent, from the $2.72 per Mcf, including a benefit of 4 cents per
Mcf from hedging activities, realized during the first nine months of 2002. In
the first nine months of 2003, the Company's worldwide average realized liquids
price was $27.36 per Bbl, which was an increase of $4.98 per Bbl, or 22 percent,
from the same period a year ago. The Company's hedging program lowered the
average realized liquids price by 19 cents per Bbl in the first nine months of
2003 while the first nine months of 2002 included a gain of one cent per Bbl
from hedging activities. International production increases also contributed
approximately $35 million in higher earnings, primarily from higher Thailand
liquids and natural gas production. The first nine months of 2003 included
after-tax gains of approximately $60 million from asset sales, including the
sale of all of the Company's stock holding in Matador Petroleum Corporation
("Matador") and the majority of its shares in TBI (see note 4 to the
consolidated financial statements in Item 1 of this report). The geothermal and
power operations added $13 million in earnings improvement in the nine months
period of 2003 as compared to the same period a year ago, primarily as a
result of the amended Salak agreements in Indonesia and the positive impact of
foreign exchange rates on results from the Company's equity interests in
gas-fired power plants in Thailand. The results in the first nine months of 2003
included an after-tax gain of $4 million in mark-to-market accruals and realized
gains/losses for non-hedge commodity derivatives recorded by Northrock, compared
with a $5 million after-tax loss in the same period a year ago.
These 2003 positive variance factors were partially offset by lower North
America production, the aforementioned higher asset impairments, higher pension
related expenses and higher dry hole costs, which reduced net earnings by
approximately $40 million, $40 million, $30 million and $10 million,
respectively, in the first nine months of 2003 compared with the same period a
year ago. North America liquids production averaged 84,000 Bbl/d in the first
nine months of 2003, down from 96,000 Bbl/d a year ago, while natural gas
production averaged 800 MMcf/d down from 910 MMcf/d for the nine months period a
year ago. Most of the production decline was due to natural declines in existing
fields in the Gulf of Mexico and the divestiture of various properties in
Canada, onshore U.S. and the Gulf of Mexico. In addition, the Company's minerals
operations contributed approximately $20 million after-tax of lower earnings in
the nine months period of 2003 as compared to the same period a year ago.
After-tax environmental and litigation expenses were $83 million in the first
nine months of 2003, compared with $62 million in the same period a year ago,
primarily due to higher litigation expenses including related outside support
costs. The first nine months of 2003 included the company-wide $23 million
restructuring charge, while the same period a year ago included a $12 million
restructuring charge for the Gulf Region business unit.
Cumulative Effects of Accounting Changes
In the first quarter of 2003, the Company recorded a non-cash $83 million
after-tax charge consisting of 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." The
Company also increased its accrued abandonment and restoration liabilities by
$268 million and increased its net properties by $138 million on the
consolidated balance sheet as a result of the adoption of SFAS No.143.
Revenues
Revenues from continuing operations for the third quarter of 2003 were $1.54
billion compared with $1.3 billion for the same period a year ago. In the first
nine months of 2003, total revenues from continuing operations were $4.95
billion compared with $3.71 billion for the same period a year ago. The
increases, in both the quarter and nine months amounts, primarily reflected
higher crude oil and natural gas prices.
-39-
OPERATING HIGHLIGHTS UNOCAL CORPORATION
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
-----------------------------------------
2003 2002 2003 2002
--------------------------------------------------------------------------------
North America Net Daily Production
Liquids (thousand barrels)
U.S. Lower 48 (a) (b) 42 52 45 54
Alaska 21 24 22 25
Canada 17 16 17 17
--------------------------------------------------------------------------------
Total liquids 80 92 84 96
Natural gas - dry basis (million cubic feet)
U.S. Lower 48 (a) (b) 595 716 650 740
Alaska 49 61 59 79
Canada 90 90 91 91
--------------------------------------------------------------------------------
Total natural gas 734 867 800 910
North America Average Prices (excluding hedging activities) (c)
Liquids (per barrel)
U. S. Lower 48 $ 27.92 $ 24.85 $ 28.04 $ 22.24
Alaska $ 29.39 $ 26.10 $ 29.87 $ 23.36
Canada $ 24.02 $ 22.70 $ 25.37 $ 20.29
Average $ 27.47 $ 24.79 $ 27.96 $ 22.18
Natural gas (per mcf)
U. S. Lower 48 $ 4.78 $ 2.95 $ 5.39 $ 2.78
Alaska $ 1.46 $ 1.20 $ 1.27 $ 1.48
Canada $ 4.96 $ 2.08 $ 5.24 $ 2.38
Average $ 4.57 $ 2.73 $ 5.05 $ 2.62
--------------------------------------------------------------------------------
North America Average Prices (including hedging activities) (c)
Liquids (per barrel)
U. S. Lower 48 $ 27.71 $ 24.84 $ 27.37 $ 22.28
Alaska $ 29.39 $ 26.10 $ 29.87 $ 23.36
Canada $ 24.02 $ 22.70 $ 25.37 $ 20.29
Average $ 27.36 $ 24.78 $ 27.59 $ 22.20
Natural gas (per mcf)
U. S. Lower 48 $ 4.82 $ 2.97 $ 5.11 $ 2.87
Alaska $ 1.46 $ 1.20 $ 1.27 $ 1.48
Canada $ 4.64 $ 2.10 $ 4.93 $ 2.44
Average $ 4.57 $ 2.75 $ 4.79 $ 2.69
--------------------------------------------------------------------------------
(a)Includes proportional interests in production of equity investees.
(b)Includes minority interests of :
Liquids - 8 1 8
Natural gas - 94 7 96
Barrels oil equivalent - 24 2 24
(c)Excludes gains/losses on derivative positions not accounted for as
hedges and ineffective portions of hedges.
-40-
OPERATING HIGHLIGHTS (CONTINUED) UNOCAL CORPORATION
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
-----------------------------------------
2003 2002 2003 2002
--------------------------------------------------------------------------------
International Net Daily Production (d)
Liquids (thousand barrels)
Far East 59 52 58 53
Other (a) 20 20 20 20
--------------------------------------------------------------------------------
Total liquids 79 72 78 73
Natural gas - dry basis (million cubic feet)
Far East 883 859 888 855
Other (a) 74 83 91 79
--------------------------------------------------------------------------------
Total natural gas 957 942 979 934
International Average Prices (d) (e)
Liquids (per barrel)
Far East $26.65 $23.99 $26.92 $21.95
Other $29.19 $26.94 $27.74 $24.62
Average $27.20 $24.84 $27.11 $22.62
Natural gas (per mcf)
Far East $2.86 $2.84 $2.79 $2.74
Other $2.93 $2.80 $2.88 $2.70
Average $2.87 $2.83 $2.80 $2.74
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
Worldwide Net Daily Production (a) (b) (d)
Liquids (thousand barrels) 159 164 162 169
Natural gas - dry basis (million cubic feet) 1,691 1,809 1,779 1,844
Barrels oil equivalent (thousands) 441 466 458 476
Worldwide Average Prices (excluding hedging activities) (c)
Liquids (per barrel) $27.34 $24.82 $27.55 $22.37
Natural gas (per mcf) $3.60 $2.78 $3.79 $2.68
Worldwide Average Prices (including hedging activities) (c) (e)
Liquids (per barrel) $27.28 $24.81 $27.36 $22.38
Natural gas (per mcf) $3.60 $2.79 $3.68 $2.72
--------------------------------------------------------------------------------
(a)Includes proportional interests in production of equity investees.
(b)Includes minority interests of :
Liquids - 8 1 8
Natural gas - 94 7 96
Barrels oil equivalent - 24 2 24
(c)Excludes gains/losses on derivative positions not accounted for as
hedges and ineffective portions of hedges.
(d)International production is presented utilizing the economic interest method.
(e)International did not have any hedging activities.
Selected Costs and Other Deductions
Administrative and general expense in 2003 included a $27 million pre-tax charge
as a result of the restructuring program announced in June and an additional $10
million pre-tax restructuring charge in September. The increase in
administrative and general expense also reflected higher pension-related
expenses in 2003.
-41-
Exploration and Production
The Company engages 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. Lower 48, Alaska and
Canada oil and gas operations. The emphasis of the U.S. Lower 48 operations is
on the onshore, the shelf and deepwater areas of the Gulf of Mexico region and
the Permian and San Juan Basins in west Texas and New Mexico. A substantial
portion of the crude oil and natural gas produced in the U.S. Lower 48
operations is sold to the Company's Trade business segment. Natural gas produced
by Northrock in Canada is also sold to the Company's Trade business segment. The
remainder of U.S. Lower 48 and Canada production is sold to third parties. In
Alaska, the majority of natural gas production, pursuant to agreements with the
purchaser of the Company's former agricultural products business, is sold to a
fertilizer plant in Nikiski, Alaska. In addition, the Company uses hydrocarbon
derivative financial instruments such as futures, swaps and options to hedge
portions of the Company's exposure to commodity price fluctuations.
Third Quarter Results: Earnings from continuing operations were $104 million in
the third quarter of 2003 compared to $21 million for the same period a year
ago, which was an increase of $83 million. The increase was primarily due to
higher natural gas and liquids prices, which increased net earnings by
approximately $90 million. In addition, the current quarter included
approximately $30 million after-tax in gains on asset sales primarily from the
sale of TBI stock. The current quarter results also reflected approximately $20
million after-tax in lower exploration expenses, including dry hole costs. The
third quarter of 2002 included an after-tax loss of $5 million in mark-to-market
accruals and realized gains/losses for non-hedge commodity derivatives recorded
by Northrock. These positive factors were partially offset by lower natural gas
and liquids production, which reduced after-tax earnings by approximately $10
million. The current quarter also included after-tax impairment charges of $47
million primarily related to the Gulf of Mexico assets held for sale.
Nine Months Results: Earnings from continuing operations were $365 million in
the first nine months of 2003 compared to $31 million for the same period a year
ago. The increase was primarily due to higher natural gas and liquids prices,
which increased net earnings by approximately $355 million. In addition, the
Company recorded approximately $55 million after-tax in asset sale gains,
primarily from the sale of TBI and Matador common stock. The first nine months
of 2003 included an after-tax gain of $4 million in mark-to-market accruals and
realized gains/losses for non-hedge commodity derivatives recorded by Northrock,
while the comparable period a year ago included an after-tax loss of $5 million.
These positive factors were partially offset by the aforementioned impairments
primarily related to the Gulf of Mexico assets held for sale, lower natural gas
and liquids production, higher exploration expenses including dry hole costs,
which reduced after-tax earnings by approximately $47 million, $40 million and
$25 million, respectively. The nine months period of 2002 included a $12 million
after-tax impairment in the Alaska business unit and a $12 million after-tax
restructuring charge in the Gulf Region business unit.
International - Unocal's International operations include oil and gas
exploration and production activities outside of North America. The Company
operates or participates in production operations in Thailand, Indonesia,
Myanmar, Bangladesh, the Netherlands, Azerbaijan, the Democratic Republic of
Congo and Brazil. International operations also include the Company's
exploration activities and the development of energy projects primarily in Asia,
Australia, Latin America and West Africa.
Third Quarter Results: Earnings from continuing operations totaled $136 million
in the current quarter, unchanged from the same period a year ago. Higher
liquids and natural gas prices improved net earnings by $11 million. The results
for the current quarter also benefited from $7 million in lower exploration
expenses, including dry hole costs. These positive factors were offset by
approximately $15 million in increased income tax expense due to higher
effective tax rates, primarily caused by a weakening in the U.S. dollar against
the Thai baht.
-42-
Nine Months Results: Earnings from continuing operations totaled $423 million in
the first nine months of 2003 compared to $363 million in the same period a year
ago, which was an increase of $60 million. The increase was primarily due to
approximately $55 million in higher liquids and natural gas prices and $35
million in higher liquids and natural gas production. These positive factors
were partially offset by approximately $25 million in higher DD&A expense
(including asset retirement obligation accretion) and $5 million in increased
income taxes due to higher effective tax rates, primarily due to the weakening
of the U.S. dollar against the Thai baht. The higher natural gas production was
primarily from increased demand tied to higher electric power needs in Thailand
and higher production in Bangladesh. Higher liquids production was due to the
Yala-Plamuk and Pailin Phase 2 projects in Thailand.
TRADE
The Trade segment externally markets the majority of the Company's worldwide
liquids production and North American natural gas production, excluding
production of the Alaska business unit. It is also responsible for executing
various derivative contracts on behalf of the Exploration and Production segment
in order to manage the Company's exposures to commodity price changes. The Trade
segment also purchases liquids and natural gas from certain of the Company's
royalty owners, joint venture partners and unaffiliated oil and gas producing
and trading companies for resale. In addition, the segment trades hydrocarbon
derivative instruments, for which hedge accounting is not used, to exploit
anticipated opportunities arising from commodity price fluctuations. The segment
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 the Company's potential loss from likely changes in market
prices.
Third Quarter Results: Earnings from continuing operations totaled $3 million in
the current quarter compared to a loss of $1 million in the same period a year
ago. The higher results reflect gains from natural gas and crude oil trading
activities, which were positively impacted by volatile commodity prices.
Sales and operating revenues from the Trade business segment were $633 million
in the current quarter compared to $623 million in the same quarter a year ago,
which was an increase of $10 million. These revenues represented approximately
43 percent and 48 percent of the Company's total sales and operating revenues
for the third quarters of 2003 and 2002, respectively. Increases in natural gas
and crude oil revenues, as a result of higher prices, were partially offset by
lower natural gas and crude oil volumes.
Nine Months Results: The results for the first nine months were a loss of $2
million compared to earnings of $1 million in the same period a year ago. The
decrease was primarily due to lower results related to domestic crude oil and
natural gas marketing activities, which were negatively impacted by volatile
commodity prices.
Sales and operating revenues were $2.29 billion in the first nine months of 2003
compared to $1.72 billion in the same period a year ago, which was an increase
of` $568 million. These revenues represented approximately 48 percent and 47
percent of the Company's total sales and operating revenues for the first nine
months of 2003 and 2002, respectively. In the first nine months of 2003, natural
gas revenues increased by approximately $414 million and crude oil revenues
increased by approximately $157 million, primarily due to higher commodity
prices, as compared to the same period a year ago. Higher commodity prices were
partially offset by lower crude oil and natural gas volumes.
-43-
MIDSTREAM
The Midstream segment is comprised of the Company's equity interests in certain
petroleum pipeline companies, wholly-owned pipeline systems throughout the U.S.,
and the Company's North America gas storage business.
Third Quarter Results: Earnings from continuing operations totaled $16 million
in the current quarter compared to $17 million in the same period a year ago.
The decrease was due primarily to $4 million after-tax in impairments related to
the Trans-Andean oil pipeline, which transports crude oil from Argentina to
Chile and a U.S. pipeline associated with exploration and production assets held
for sale in the Gulf of Mexico region. The results for the prior year quarter
included a $2 million after-tax impairment of assets of a U.S. pipeline company
in which the Company owns an equity interest.
Nine Months Results: Earnings from continuing operations totaled $52 million in
the first nine months of 2003 compared to $59 million in the same period a year
ago. The decrease was due primarily to $5 million in lower results from the
pipelines and gas storage businesses and $3 million from expenses related to the
Baku-Tbilisi-Ceyhan ("BTC") pipeline project. The nine months results of 2003
and 2002 also reflect the aforementioned asset impairments.
GEOTHERMAL AND POWER OPERATIONS
The Geothermal and Power Operations business segment produces geothermal steam
for power generation, with operations in the Philippines and Indonesia. The
segment's activities also include the operation of geothermal steam-fired power
plants in Indonesia and equity interests in gas-fired power plants in Thailand.
The Company's non-exploration and production business development activities,
primarily power-related, are also included in this segment.
Third Quarter Results: Earnings from continuing operations totaled $19 million
in the current quarter compared to $5 million in the same period a year ago. The
current period results were positively impacted by higher steam prices and
generation in Indonesia. In addition, the current period benefited from improved
results from the Company's equity interests in gas-fired power plants in
Thailand.
Nine Months Results: Earnings from continuing operations totaled $38 million in
the first nine months of 2003 compared to $25 million in the same period a year
ago. The current period results reflect improvements from the amended Salak
agreements in Indonesia. In addition, the nine months results in 2003 reflect
higher results from the Company's equity interests in gas-fired plants in
Thailand and lower non-exploration and production business development expenses
as compared to the same period a year ago.
CORPORATE AND OTHER
Corporate and Other includes general corporate overhead, miscellaneous
operations (including real estate activities, carbon and minerals) and other
corporate unallocated costs (including environmental and litigation expense).
Net interest expense represents interest expense, net of interest income and
capitalized interest.
Third Quarter Results: The results for the current quarter were a loss of $126
million compared to a loss of $79 million in the same period a year ago.
After-tax expenses for environmental and litigation matters for the current
quarter were $38 million compared to $25 million after-tax for the same period a
year ago, primarily reflecting higher outside litigation support costs. In
addition, the current quarter reflected approximately $10 million after-tax in
lower results from the Company's minerals business, $10 million after-tax in
higher pension related expenses, a $6 million in restructuring charge and $4
million in higher net after-tax interest expense primarily due to lower interest
income and lower capitalized interest.
-44-
Nine Months Results: The results for the first nine months were a loss of $338
million compared to a loss of $245 million in the same period a year ago. The
first nine months of 2003 included $23 million after-tax restructuring charge
and higher pension related expenses of approximately $30 million. After-tax
expenses for environmental and litigation matters for the nine months of 2003
were $83 million compared to $63 million after-tax for the same period a year
ago. In addition, the nine months results of 2003 reflect approximately $20
million after-tax in lower earnings from the minerals business.
Restructuring
In June 2003, the Company accrued a $27 million pre-tax restructuring charge and
adopted a plan for streamlining the organizational structures in order to align
them with the Company's portfolio requirements and business needs. In the third
quarter of 2003, the Company accrued an additional $10 million pre-tax
restructuring charge to reflect continued streamlining of the organizational
structures. The charge is included in selling, administrative and general
expense on the consolidated earnings statement. The following table reflects the
2003 restructuring activity by quarter:
----------------------- ----------------- ----------- ------------ -------------
Millions of dollars # Employees added Training / Post-
(except employees) to restructuring Termination Outplacement retirement
plan Costs Costs Benefit Costs
----------------------- ----------------- ----------- ------------ -------------
1st Quarter Accrual - - - -
----------------------- ----------------- ----------- ------------ -------------
1st Quarter Payments - - -
----------------------- ----------------- ----------- ------------ -------------
Liability at 3/31/2003 - - -
----------------------- ----------------- ----------- ------------ -------------
2nd Quarter Accrual 219 21 2 4
----------------------- ----------------- ----------- ------------ -------------
2nd Quarter Payments - - -
----------------------- ----------------- ----------- ------------ -------------
Liability at 6/30/2003 21 2 4
----------------------- ----------------- ----------- ------------ -------------
3rd Quarter Accrual 127 9 - 1
----------------------- ----------------- ----------- ------------ -------------
3rd Quarter Payments 2 - -
----------------------- ----------------- ----------- ------------ -------------
Liability at 9/30/2003 28 2 5
----------------------- ----------------- ----------- ------------ -------------
The majority of the liabilities are expected to be paid in 2003 and 2004. At
September 30, 2003, 321 of 346 employees had been terminated or had been advised
of planned termination dates as a result of the plan.
In June 2002, the Company's Gulf Region business unit, which is part of the U.S.
Lower 48 operations in the Exploration and Production segment, adopted a
restructuring plan that resulted in the accrual of a $19 million pre-tax
restructuring charge. The charge included the estimated costs of terminating 202
employees, all of whom were terminated in 2002. At September 30, 2003,
approximately $18 million of the restructuring costs had been paid and charged
against the liability, leaving accrued costs of $1 million on the consolidated
balance sheet. The remaining costs are expected to be paid by the end of 2003.
In November 2002, the Company adopted a restructuring plan that resulted in the
accrual of a $4 million pre-tax restructuring charge related to Exploration and
Production operations in Alaska. The restructuring charge reflected the costs of
terminating 46 employees, of whom 43 had been terminated as of September 30,
2003. At September 30, 2003, approximately $3 million of the restructuring costs
had been paid. The plan will essentially be completed at the end of 2003.
-45-
FINANCIAL CONDITION
Cash flows from operating activities, including working capital and other
changes, were $1.65 billion for the nine months ended September 30, 2003,
compared with $1.23 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 higher income tax
payments, compared to the same period a year ago, and the repayment of the
outstanding balance under the Company's accounts receivable securitization
program.
Pre-tax proceeds from asset sales (including those classified as discontinued
operations) were $354 million for the nine months ended September 30, 2003. The
Company received $122 million from the sale of most of its shares in Tom Brown
Inc. and $80 million from the sale of its common stock in Matador. The Company
also completed the sale of various properties in Canada, onshore U.S. and the
Gulf of Mexico, which netted the Company approximately $118 million in proceeds.
Other miscellaneous property sales netted the Company $23 million in proceeds
and $11 million related to a participation payment was received from the
purchaser of the Company's former West Coast refining, marketing and
transportation assets covering price differences between California Air
Resources Board Phase 2 gasoline and conventional gasoline. Pre-tax proceeds
from asset sales (including those classified as discontinued operations) were
$64 million for the nine months ended September 30, 2002. These proceeds
included $29 million from the sale of oil and gas producing properties in the
U.S. by the Company's Pure subsidiary. Sale proceeds also included $17 million
from various other oil and gas asset sales, $15 million in other miscellaneous
properties and $3 million related to the aforementioned participation payment.
Capital expenditures were $1.3 billion for the first nine months of 2003
compared with $1.25 billion in the same period a year ago. Capital expenditures
for 2003 are currently forecast at approximately $1.75 billion. Capital
expenditures reflect higher spending on development projects, including the
Caspian crude oil development and the Baku-Tbilisi-Ceyhan ("BTC") pipeline
project, the West Seno field in deepwater Indonesia and Mad Dog field in the
Gulf of Mexico. In the first nine months of 2003, the Company's capital
expenditures included approximately $580 million for the development of
undeveloped proved oil and gas reserves, primarily in Indonesia, Azerbaijan,
Thailand and the deepwater Gulf of Mexico.
The Company's total consolidated debt, including current maturities, at
September 30, 2003, was $3.12 billion, approximately $100 million more than at
the end of 2002. During the first nine months of 2003, the Company retired $89
million in 9.25% debentures and paid down $10 million of medium-term notes which
matured. The Company also repurchased $15 million of the $200 million
outstanding balance in 6.375% notes due in 2004, $10 million of the $350 million
outstanding balance in 7.35% notes due in 2009 and repaid $20 million of 6.20%
Industrial Development Revenue Bonds. In addition, the Company prepaid a $5
million capital lease on a natural gasoline plant and paid down an additional $7
million of miscellaneous debt. These decreases in debt and capital leases were
offset by $154 million drawn under the Overseas Private Investment Corporation
("OPIC") Financing Agreement for the first phase of the West Seno development
project in Indonesia. In addition, effective in the third quarter of 2003, FASB
Interpretation No. 46 required the Company to consolidate DSPL, resulting in the
reporting of $78 million as long-term debt on the consolidated balance sheet at
September 30, 2003.
In July the Company paid off the $252 million limited partner interest in Spirit
Energy 76 Development, L.P. of which $242 million would have been reclassified
as long-term debt in the third quarter pursuant to FASB Interpretation No. 46
(see note 13 for further detail on the Company's long-term debt).
Cash and cash equivalents on hand totaled $485 million at September 30, 2003, up
from $168 million at the end of 2002.
-46-
The Company has two primary credit facilities in place: a $400 million 364-day
credit agreement and a $600 million 5-year credit agreement, maturing October
2006. No borrowings were outstanding under either facility at September 30,
2003. 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 the Company's total debt to total
capitalization ratio to 70 percent (total capitalization is defined as total
debt plus total equity, with the Company's convertible preferred securities
included as equity in the ratio calculation.) In addition, the Company also has
a 3-year $295 million Canadian dollar-denominated non-revolving credit facility
with a variable rate of interest. At September 30, 2003, the borrowing under the
Canadian credit facility translated to $216 million, using applicable foreign
exchange rates.
Based on current commodity prices and current development projects, the Company
expects cash generated from operating activities, asset sales and cash on hand
in 2003 to be sufficient to cover its operating and capital spending
requirements and to meet dividend payments and to pay down debt. The Company has
substantial borrowing capacity to enable it to meet unanticipated cash
requirements.
The Company relies on the commercial paper market, its accounts receivable
securitization program and its revolving credit facilities to cover near-term
borrowing requirements. At September 30, 2003, the Company did not have an
outstanding balance under its accounts receivable securitization program, which
was at $108 million at year-end 2002. The Company also had in place a universal
shelf registration statement as of September 30, 2003, 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 the Company's needs
and market conditions. From time to time, the Company may also look to fund some
of its long-term projects using other financing sources, including multilateral
and bilateral agencies.
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 the Company's ability to raise
short-term and long-term financing. As a result of the Company's current
investment grade ratings, the Company has access to both the commercial paper
and bank loan markets. The Company currently has a BBB+ / Baa2 credit rating by
Standard & Poor's and Moody's, respectively, and an A-2 / Prime-2 for its
commercial paper ratings. Moody's and Standard & Poor's outlooks remained stable
for the Company's long term debt and commercial paper ratings. The Company does
not believe it has a significant exposure to liquidity risk in the event of a
credit rating downgrade.
-47-
ENVIRONMENTAL MATTERS
The Company is committed to operating its business in a manner that is
environmentally responsible. This commitment is fundamental to the Company's
core values. As part of this commitment, the Company has procedures in place to
audit and monitor its environmental performance. In addition, it has implemented
programs to identify and address environmental risks throughout the Company.
Costs associated with identified environmental remediation obligations have been
accrued in a reserve for such obligations. At September 30, 2003, the Company's
remediation reserve totaled $265 million, of which $144 million was included in
current liabilities. During the nine months period ended September 30, 2003,
cash payments of $53 million were applied against the reserve and $77 million
was added to the reserve. The Company 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 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, the Company estimates that it could incur
possible additional remediation costs aggregating approximately $210 million.
The Company's total environmental reserve and possible additional liability
amounts are grouped into the following four categories.
At September 30, 2003
----------------------------
Possible
Additional
Millions of dollars Reserve Costs
--------------------------------------------------------------------------------
Superfund and similar sites $ 16 $ 15
Active Company facilities 32 30
Company facilities sold with retained liabilities
and former Company-operated sites 99 80
Inactive or closed Company facilities 118 85
--------------------------------------------------------------------------------
Total $ 265 $ 210
================================================================================
Also see notes 16 and 17 to the consolidated financial statements in Item 1 of
this report for additional information on environmental related matters.
During the first nine months of 2003, the Company accrued $42 million related to
sites in the "Inactive or closed Company facilities" category primarily for the
Guadalupe oil field located on the central California coast and for remediation
projects at the Company's former refinery in Beaumont, Texas.
For the Guadalupe oil field site, it was determined that contaminated soil
excavated from the site will probably be taken to an offsite landfill for
disposal. The soil is contaminated with diluent, a kerosene-like additive used
in the field's former operations. Previously, the Company had planned to
remediate the soil on-site; however, a preliminary draft report for the
ecological risk study being conducted indicates that on-site remediation is not
feasible. The provisions recorded for the site include the costs for the offsite
disposal alternative. The provisions recorded for the Guadalupe oil field also
include estimated costs for remediation work that is ongoing at the site. This
work includes groundwater monitoring, operation and maintenance of remedial
systems, restoration, agency oversight, permitting, and site assessment. The
provisions for these costs are based on data from various studies and
assessments that have been completed for the site in conjunction with data
provided by the project management system the Company has in place.
A provision was also recorded for the Company's former Beaumont, Texas refinery.
The Company has been working with the Texas Commission on Environmental Quality
("TCEQ") to develop plans for closing impoundments used in the site's former
operations and for other remediation projects. In the first nine months of 2003,
the Company recorded a provision for the revised estimated costs of the
impoundment closure plan based on the TCEQ initial draft permit that was issued
for the site.
-48-
During the first nine months of 2003, provisions of $27 million were recorded
for the "Company facilities sold with retained liabilities and former
Company-operated sites" category. These provisions included the estimated
cleanup costs for oil fields located in Michigan and California that were
formerly operated by the Company. The estimated costs are based on assessments
recently performed at the sites, higher than anticipated volumes of contaminated
soil at existing sites and higher remediation costs for soil excavation and
disposal than originally anticipated. The provisions for this category of sites
were also the result of revised remediation cost estimates that were identified
during the first and second quarters of 2003 for former service station sites.
The Company recorded provisions of $8 million during the first nine months of
2003 for the "Active Company facilities" category of sites. The provisions were
primarily for the remedial investigation and feasibility study (RI/FS) being
performed at a molybdenum mine located in Questa, New Mexico, that is owned by
the Company's Molycorp, Inc. ("Molycorp") subsidiary. Molycorp has been working
closely with the U.S. Environmental Protection Agency and the State of New
Mexico in conducting the RI/FS at the mine during the year. The RI/FS is being
performed to determine if past mining operations have had an adverse impact on
the environment. Numerous additions and changes to the RI/FS scope have been
required by the agencies, which will require a higher level of effort than
originally projected.
During the first nine months of 2003, estimated possible additional costs in
excess of amounts included in the reserves for remediation obligations decreased
by $35 million. The decrease was primarily for sites in the "Active Company
facilities" category, as a result of the reclassification of costs to asset
retirement obligations under SFAS No. 143 for the Company's Molycorp subsidiary
(see note 2 for further detail). The decrease was also the result of the Company
lowering its estimated costs for the "Inactive or closed Company facilities"
category of sites by $20 million. These costs were included in the amounts added
to the reserve for the Guadalupe oil field and the Beaumont Refinery sites as
discussed above.
Partially offsetting the foregoing decreases was an increase of $5 million in
possible additional costs for the "Superfund and similar sites" category. The
increase is based on preliminary information that the Company has received
regarding possible payments for remediation-related work that may need to be
made for two sites located in California. Estimated possible additional costs
for the "Company facilities sold with retained liabilities and former
Company-operated sites" category also increased by $5 million during the first
nine months of 2003. This increase was primarily for costs that may be incurred
related to the cleanup of various sites that were part of the auto/truckstop
system that the Company sold in 1993.
-49-
OUTLOOK
Certain of the statements in this discussion, as well as other forward-looking
statements within this document, contain estimates and projections of amounts of
or increases/decreases in future revenues, earnings, cash flows, capital
expenditures, assets, liabilities and other financial items and of future levels
of or increases/decreases in reserves, production, sales including related costs
and prices, drilling activities and other statistical items; plans and
objectives of management regarding the Company's future operations, products and
services; and certain assumptions underlying such estimates, projection plans
and objectives. While these forward-looking statements are made in good faith,
future operating, market, competitive, legal, economic, political,
environmental, and other conditions and events could cause actual results to
differ materially from those in the forward-looking statements. See pages 56
through 64 of Management's Discussion and Analysis in Item 7 of the Company's
2002 Annual Report on Form 10-K for a discussion of certain of such conditions
and events.
The economic situation in Asia, where most of the Company's international
activity is centered, is still recovering with positive signs showing in the
region. The Company looks at the natural gas market in Asia as one of its major
strategic investments and believes that the governments in the region are
committed to undertaking the reforms and restructuring necessary to enable their
nations to continue their recoveries from the downturn. Volatile energy prices
are expected to continue to impact financial results. The Company expects energy
prices to remain volatile due to changes in climate conditions, worldwide
demand, crude oil and natural gas inventory levels, production quotas set by
OPEC, current and future worldwide political instability, especially concerning
Iraq and Nigeria, security and other factors.
The Company currently estimates its full-year 2003 production to average between
450,000 to 455,000 BOE per day. This production forecast includes the impact of
the sale of nearly 7,000 BOE per day of equity production from the Company's
holdings in TBI and Matador, the sale of more than 20,000 BOE per day of
production to Forest Oil Corporation and others during the fourth quarter, the
associated production loss of approximately 5,000 BOE per day from other
divestitures that the Company has completed so far this year, and the start-up
delay of the West Seno field in Indonesia. The Company's total actual production
for the year could also be impacted by cost recovery volume fluctuations under
the Company's various foreign PSCs due to changes in commodity prices, demand
for natural gas in Thailand, the rate of ramp-up of production from the West
Seno field in Indonesia and production and exploration performance in the Gulf
of Mexico.
For the fourth quarter of 2003, the Company has hedged 25 million MMBtu (million
British thermal units) of Lower 48 natural gas production and 4 million Bbl of
Lower 48 crude oil production, together representing approximately 70 percent of
expected Lower 48 BOE production volume. Fourth quarter hedges include fixed
price sales for 16 million MMBtu of natural gas at $5.99 per MMBtu and 3.1
million Bbl of crude oil at $31.14 per Bbl. In addition, the Company has hedged
9 million MMBtu of natural gas with pricing collars between $4.62 and $3.77 per
MMBtu and 600,000 Bbl of crude oil with collars between $32.24 and $27.41 per
Bbl. Based on current prices, the Company's net earnings for the fourth quarter
are expected to change $8 million for each $1 change in the Company's average
worldwide realized price for crude oil and $3.5 million for every 10-cent change
in its average realized North America natural gas price, excluding the effect of
hedging activities.
The Company has an active exploratory drilling program and forecasts fourth
quarter pre-tax dry hole costs of $50 million to $65 million.
-50-
Exploration and Production - North America
U.S. Lower 48
The Company continues its deep shelf program in the Gulf of Mexico. Production
at the Red Pepper shelf discovery on High Island Block 37 commenced in October,
adding to the Company's Harvest deep shelf discovery on West Cameron Block 44
that commenced in late June and two other deep shelf producing fields. In late
October, the Company drilled a successful appraisal well on its Harvest deep
shelf field. The well was drilled to a total depth of 14,322 feet and
encountered more than 140 feet of net natural gas pay. The Company expects to
place the Harvest-2 well on production in mid-December and is in the process of
formulating plans for a second appraisal well. The Company holds a 44-percent
working interest in the field. The Company expects to continue its deep shelf
drilling activity for the remainder of 2003, which is expected to bring the
total number of deep shelf exploratory wells drilled to 11 for the year.
In the Gulf of Mexico deepwater, the Company completed a discovery well on the
St. Malo prospect located on Walker Ridge Block 678. The discovery well
encountered more than 450 feet of net oil pay. Based on the evaluation of this
well, the Company expects to begin an appraisal program in 2004. The Company
holds a 28.75 percent working interest in the prospect. In addition, the Company
farmed-in to an exploratory well which is currently being drilled on the Puma
prospect to earn a 15 percent working interest. The prospect is an exploration
play offsetting the Mad Dog discovery. The Company expects to drill an
additional well before the end of 2003.
The Company continues the funding of the development of the Mad Dog field in
which the Company has a 15.6 percent non-operating working interest. The Company
anticipates first production in the first half of 2005, with gross expected peak
production of 75 MBbl/d of liquids and 30 MMcf/d of natural gas in 2007. The
Company also expects the co-venture integrated project team of the K-2 discovery
to complete a development plan by the end of 2003 with project sanctioning to
occur in early 2004. The Company and its co-venturers are working on development
options with the aim of sanctioning development of the Champlain discovery in
2004. The Company completed a successful appraisal well on the Champlain
discovery in July 2003 and has a 30-percent working interest in the prospect.
The Company continues to move forward with studies on development options for
its Trident discovery in the deepwater Gulf of Mexico. The Company is in
discussions with all the operators in the area about development scenarios and
joint development planning. The Company is the operator of the discovery and has
a 59.5 percent working interest in a seven-block area.
In the fourth quarter of 2003, the Company expects to complete the sale of the
70 properties held for sale in the Gulf of Mexico and onshore Louisiana to
Forest Oil Corporation and others for net proceeds totaling approximately $233
million. The effective date of the sale was July 1, 2003 (see notes 5 and 12 for
discussions related to these assets). Of the total expected proceeds, $218
million had been received from Forest Oil as of November 12, 2003, with an
additional $15 million expected to be received by year-end from Forest and other
working interest owners in the properties who exercised their preferential
rights. The Company continues to move forward with the divestiture of an
additional 30 properties held for sale in the Gulf of Mexico region. The sale of
these remaining properties is expected to close later in the fourth quarter of
2003.
In late October 2003, the Company completed a property exchange with Apache
Corporation that consolidated both companies' interests in two oil and gas
fields in the Gulf of Mexico region. Under the terms of the exchange, the
Company received Apache's 13 percent working interest in the Unocal-operated
Ship Shoal 208 field and an undisclosed amount of cash in exchange for Unocal's
majority interest in the Lake Pagie field in Terrebone Parish, Louisiana. The
Company now holds 100 percent of the Ship Shoal 208 field, which covers three
Gulf of Mexico blocks. The Company expects to record a pre-tax gain of
approximately $21 million from the transaction in the fourth quarter 2003. This
consolidation of interests is part of the restructuring program began by the
Company earlier this year to improve the profitability and sustainability of its
Lower-48 exploration and production businesses. The Company anticipates
completion of the divestiture program by the end of 2003 (see note 12 to the
consolidated financial statements in Item 1 of this report).
-51-
Alaska
The Ninilchik Unit, on the South Kenai peninsula, began first production from
two wells in September 2003 and the Company expects the remaining three wells to
be brought on-line over the remainder of the year. The two wells are currently
producing 16 MMcf/d gross. The Company has a 40 percent non-operating interest
in the unit. Sales of Ninilchik natural gas to Enstar are scheduled to commence
in January 2004.
Exploration and Production - International
Far East
Thailand: Demand for natural gas from the Company's fields has been strong as a
result of reduced production from adjacent fields operated by other companies.
This temporary spike in demand for the Company's production has now returned to
normal levels as adjacent fields operated by other companies solved their
delivery problems. The Company signed a heads of agreement with PTT Public Co.,
Ltd. ("PTT"), which is intended to amend and extend two of Unocal's gas sales
contracts, while increasing gross contracted sales volumes from 740 MMcf/d to
850 MMcf/d in 2006, and to 1,240 MMcf/d in subsequent years. The Company and
its partners also signed an agreement in October 2003 with PTT to increase gross
contracted gas sales volumes from the Pailin field by nearly 12-percent
to 368 MMcf/d.
The Company expects higher average liquids production, with the full-year effect
of crude oil production from its Yala field. In September 2003, the Company
filed notice with the government of Thailand seeking approval for the second
phase of development of the Company's offshore oil fields. The second phase is
designed to double gross oil production from the Yala and Plamuk fields to
40,000 barrels per day. Current plans call for the required new facilities to be
installed by mid-2005 with start-up of new production commencing shortly
thereafter. The Company has a 71.25 percent working interest in the Yala field
(62 percent net of royalty). The Company will continue to explore for and
develop additional oil and gas resources in the Gulf of Thailand and support the
efforts of PTT Exploration and Production PLC ("PTTEP") in the development of
the Arthit gas field in the gulf. The Company has a 16-percent working interest
in the Arthit gas field.
Indonesia: The Company's Unocal Ganal, Ltd. ("Unocal Ganal"), subsidiary has
made a significant gas-condensate and oil discovery on the deepwater Gehem
prospect in the Ganal production-sharing contract area, 3.5 miles south of the
Ranggas field offshore East Kalimantan, Indonesia. The Gehem-1 well encountered
617 feet of net gas and gas-condensate pay and 18 feet of net oil pay. The well
was drilled in 5,981 feet of water to a total vertical depth of 15,241 feet.
More than 400 feet of the net pay was in a stratigraphic interval that had not
been penetrated during drilling in the nearby Ranggas field. The results of the
Gehem-1 well indicate possibly significant oil and condensate accumulations in
the deeper untested trend underlying the existing Gada, Gula, and Ranggas
discoveries. The Company expects to complete the Gehem-2 appraisal well during
the fourth quarter. Unocal Ganal is the operator of the Ganal PSC and holds an
80-percent working interest.
The Company's new production from the deepwater West Seno oil and gas field came
on line in early August 2003. The Company has experienced facility related
start-up and processing issues, some of which have been corrected and others are
still being addressed. Gross production for the third quarter from West Seno
averaged more than 5,400 BOE per day. The Company had expected average
production of nearly 20,000 BOE per day from West Seno in the third quarter. The
Company will continue to drill additional development wells, which are expected
to ramp up gross production from the field up to 15,000 to 20,000 BOE per day by
year-end. The Company expects to achieve peak gross production rates of 35,000
to 45,000 BOE per day from Phase 1, rising to 55,000 to 65,000 BOE per day when
Phase 2 is completed. Gross development costs for the first phase are expected
to be approximately $500 million with an additional $240 million for the second
phase (Unocal's net share is expected to be approximately $450 million and $215
million for the first and second phases, respectively). The Company and its
co-venturer completed financing arrangements for a portion of the total costs
through the Overseas Private Investment Corporation in late March 2003 through
two loans. One loan is for $300 million and covers the first phase, and the
other loan is for $50 million and is for the second phase. The loan associated
with the second phase is still subject to a final construction contract being
obtained.
-52-
The Company's Unocal Rapak, Ltd. ("Unocal Rapak"), subsidiary successfully
completed drilling the Ranggas Selatan-1 appraisal well, extending the Ranggas
field to the south on the Rapak production-sharing contract area. The Selatan-1
well was drilled to a true vertical depth of 10,243 feet, and penetrated 187
feet of net oil pay and 258 feet of net gas pay in several zones of high quality
reservoir rock. The Selatan-1 well was drilled 1 mile south of the Ranggas-1
discovery well and 5.7 miles north of the Gehem-1 well. The Company is
conducting conceptual engineering studies for the possible development of the
Ranggas field.
The Company is planning to have the Ranggas development project ready for
government approval by early next year. The Company plans to move the Ranggas
project along while assessing the deep potential and options for co-development
with the Gehem field. Unocal Rapak is operator of the Rapak PSC area and holds
an 80-percent working interest.
The Company is currently drilling a second deep appraisal well in the Sadewa
field in the East Kalimantan PSC area to test for oil. The Sadewa discovery well
was drilled in 2002 and found both natural gas and oil. The oil play found near
the bottom of the well provided encouragement for deeper oil potential that
could not be fully evaluated at the time. The first appraisal well also found
both natural gas and oil. The Company holds a 50-percent working interest in the
well.
China: The Company has worked with China National Offshore Oil Corporation
("CNOOC"), China New Star Petroleum Corporation, the Shanghai Municipality and
the State Planning Commission to promote appraisal and development of natural
gas resources in the Xihu Trough, off the coast of Shanghai, in the East China
Sea. Unocal believes the area could contain significant amounts of recoverable
natural gas. The Company signed five PSCs in 2003 to explore and develop natural
gas resources. The project area covers nearly 5.4 million acres in approximately
300 feet of water. The project scope includes appraisal and development of
discovered fields, as well as further exploration potential. CNOOC will be the
operator of all five contract areas. The appraisal and exploration work for
Phase 1 of the project will focus on development of the resources in and around
the 173,000-acre Chunxiao Block. The near-term work program involves drilling
appraisal and exploration wells to prove additional resources sufficient to
warrant a first phase of commercial development. Natural gas from the project
would be delivered by pipeline 220 miles to the Zhejiang province and Shanghai
area markets. Liquids would be transported by pipeline to the Pinghu offshore
development that is 37 miles from the proposed Xihu central processing platform.
The Chinese government has encouraged the project participants to bring
production on stream as soon as possible, targeting the middle of 2005.
Production is expected to reach 250 MMcf/d within two years of first production.
The Company holds a 20-percent working interest in the five PSCs.
Other International
Azerbaijan: The Azerbaijan International Operating Company ("AIOC") consortium,
in which the Company has a 10.28% working interest, is on track with its
development of Phases I and II of the offshore Azeri field in the
Azeri-Chirag-Gunashli structure in the Azerbaijan sector of the Caspian Sea. The
project is under construction, with Phase 1 approximately 70 percent complete
and on schedule with first oil from the Phase 1 Central Azeri platform expected
early in 2005. A third phase is in early engineering and is expected to be
approved in 2004. Gross production from the combined phases, plus the currently
producing Early Oil Project in the Chirag Field, is forecasted to be over 1
MMBbl/d (gross) by 2009. This forecast is contingent upon the completion of the
BTC pipeline project and the general political risks inherent to the region. The
multi-country nature of this pipeline along with multinational participation in
the consortium, in addition to project financing from international lending
institutions like the IFC and EBRD and expected loan packages from several
export credit agencies, should help to mitigate the political risk.
-53-
Bangladesh: Natural gas sales in the country have expanded and the Company has
completed work on amending agreements to increase the Take-or-Pay volume for
natural gas sold to Petrobangla, the state oil and gas company. The new
agreement increased the Take-or-Pay volume of natural gas from 80 MMcf/d to 100
MMcf/d gross. In addition, the Company signed agreements with Petrobangla to
develop and produce natural gas from the Moulavi Bazar field located on Block
14. Under the agreement, the Company expects to produce 70 to 100 MMcf/d of
natural gas beginning in the first quarter of 2005. Total development cost of
the project is estimated at approximately $45 million. The Company also
continues to work with the government of Bangladesh and Petrobangla to develop
additional reserves and export natural gas to markets in neighboring India. At
October 31, 2003, the Company's business unit in Bangladesh had a gross
receivable balance of approximately $25 million relating to invoices billed for
natural gas and condensate sales to Petrobangla. Approximately $21 million of
the outstanding balance represented past due amounts and accrued interest for
invoices covering March through September 2003. Generally, invoices, when paid,
have been paid in full. The Company is working with Petrobangla and the
government of Bangladesh regarding the collection of the outstanding
receivables.
Myanmar: In late July 2003, the President of the United States signed the
Burmese Freedom and Democracy Act of 2003 ("the Act") and issued Executive Order
13310 expanding existing U.S. sanctions against Myanmar. It appears that this
latest action will not have a material adverse effect on revenues the Company
receives from its interests in Myanmar.
Midstream
Construction of the BTC pipeline is progressing with about 40 percent of the
project completed as of September 30, 2003. The pipeline project is planned to
have a crude oil throughput capacity of 1 million Bbl/d. Completion of the
pipeline is expected in late 2004 at an overall estimated cost of approximately
$3 billion and is expected to be in operation in early 2005. The Company has an
8.9 percent interest and is one of eleven shareholders in the BTC pipeline
project. The pipeline company anticipates financing up to 70 percent of the
pipeline's cost. The Company signed a bridge financing agreement in the third
quarter whereby the Company, along with several other participants will provide
short-term financing to the State Oil Company of the Azerbaijan Republic
("SOCAR") for purposes of funding SOCAR's share of BTC pipeline expenditures
until proceeds from the project financing are disbursed. The Company's 14.24%
share of this financing is anticipated to amount to less than $50 million with
payback, including interest, expected in the first half of 2004. In early
November 2003 the IFC and EBRD approved packages of $250 million and
$125 million, respectively, for the pipeline project. It is anticipated that
with the IFC and EBRD approved loan packages to the project that export-import
banks and other commercial lenders are likely to approve lending to the project.
The Kenai Kachemak Pipeline in Alaska was completed and is transporting natural
gas from Ninilchik to Kenai, where it is tied into the existing gas grid serving
south central Alaska.
Geothermal and Power Operations
In the Philippines, the Company's wholly-owned subsidiary Philippine Geothermal,
Inc. and two government-owned entities, the National Power Corporation and the
Power Sector Assets and Liabilities Management Corporation signed a compromise
settlement agreement covering the definitive terms of settlement in March 2003.
The parties are continuing the process of securing all necessary Philippine
government and court approvals of the settlement.
The Company's Unocal North Sumatra Geothermal, Ltd. subsidiary has agreed to
sell its rights and interest in the Sarulla geothermal project on the island of
Sumatra, Indonesia to the Indonesian state electricity company. The anticipated
sales price is $60 million. The transaction is expected to close by the end of
2003, and the Company expects to record a gain of approximately $15 million on
the transaction (see note 12 to the consolidated financial statements in Item 1
of this report).
-54-
Corporate & Other
In October 2003, the Company repurchased a portion of its outstanding note
issues both in a tender offer and open market purchases. Overall, the Company
repurchased $290 million of debt principal at a premium of approximately $32
million in October and November. This activity coupled with debt repurchasing
that occurred in late September brought the overall total of debt repurchases,
since September 1, to $300 million at a premium of $34 million.
FUTURE ACCOUNTING CHANGES
FASB Interpretation No. 46: Effective January 1, 2003, the Company adopted the
disclosure provisions of FASB Interpretation No. 46, "Consolidation of Variable
Interest Entities". The Company, as encouraged by the pronouncements of the
FASB, partially adopted the recognition (i.e., consolidation) requirements of
the Interpretation effective July 1, 2003. (See notes 2 and 14 to the
consolidated financial statements in Item 1 of this report). In addition,
because of the complexities of this rule and the FASB deferral, as set for in
FASB Staff Position No. FIN 46-6, of mandatory adoption until December 31, 2003,
the Company continues to review and may find additional material interests in
entities which could require recognition or disclosure in the financial
statements.
Consistent with SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas
Producing Companies," costs of acquiring oil and gas drilling rights have been
classified as tangible assets in property, plant and equipment. The Company
understands the staff of the SEC believes SFAS No. 19 does not provide guidance
as to whether these assets should be classified as tangible or intangible and
therefore believe SFAS No. 141, "Business Combinations," and SFAS No. 142,
"Goodwill and Other Intangible Assets," would require that drilling rights be
classified as an intangible asset. The SEC has requested the FASB to address
this perceived conflict within the related FASB statements. The resolution of
this issue will have no impact on the Company's results of operations. If the
FASB concurs with the SEC, it would result in additional disclosures and a
balance sheet reclassification of these assets from Properties-net to Intangible
Assets.
Other proposed accounting changes considered from time to time by the FASB, the
SEC and the United States Congress could materially impact the Company's
reported financial position and results of operations.
-55-
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
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 its overall risk management
strategies, the Company uses derivative financial instruments to manage and
reduce risks associated with these factors. The Company also trades hydrocarbon
derivative instruments, such as futures contracts, swaps and options to exploit
anticipated opportunities arising from commodity price fluctuations.
The Company determines the fair values of its 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 the Company feels that current exchange quotes and
assumptions regarding interest rates and volatilities are appropriate factors to
measure the fair value of its longer termed derivative instruments, other
pricing assumptions or methodologies may lead to materially different results in
some instances.
Interest Rate Risk - From time to time the Company temporarily invests its
excess cash in short-term interest-bearing securities issued by high-quality
issuers. Company 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 the Company. The Company's primary market risk exposure to
changes in interest rates relates to the Company's long-term debt obligations.
The Company manages its exposure to changing interest rates principally through
the use of 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.
The Company evaluated the potential effect that near term changes in interest
rates would have had on the fair value of its interest rate risk sensitive
financial instruments at September 30, 2003. Assuming a ten percent decrease in
the Company's weighted average borrowing costs at September 30, 2003, the
potential increase in the fair value of the Company's debt obligations and
associated interest rate derivative instruments, including the debt obligations
and associated interest rate derivative instruments of its subsidiaries, would
have been approximately $94 million at September 30, 2003.
Foreign Exchange Rate Risk - The Company conducts business in various parts of
the world and in various foreign currencies. To limit the Company's foreign
currency exchange rate risk related to operating income, foreign sales
agreements generally contain price provisions designed to insulate the Company's
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,
the Company is 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. The Company's
Canadian subsidiaries are paid in Canadian dollars for their crude oil and
natural gas sales and have Canadian dollar denominated debt outstanding.
From time to time the Company may purchase foreign currency options or enter
into foreign currency swap or foreign currency forward contracts to limit the
exposure related to its foreign currency debt or other obligations. At September
30, 2003, the Company had various foreign currency swaps and foreign currency
forward contracts outstanding related to operations in Thailand and The
Netherlands. The Company evaluated the effect that near term changes in foreign
exchange rates would have had on the fair value of the Company's combined
foreign currency position related to its outstanding foreign currency
denominated debt, foreign currency swaps and forward contracts. Assuming an
adverse change of ten percent in foreign exchange rates at September 30, 2003,
the potential decrease in fair value of the foreign-currency denominated debt,
foreign currency swaps and foreign currency forward contracts of the Company and
its subsidiaries would have been approximately $25 million at September 30,
2003.
-56-
Commodity Price Risk - The Company is a producer, purchaser, marketer and trader
of certain hydrocarbon commodities such as crude oil and condensate, natural gas
and refined products and is subject to the associated price risks. The Company
uses hydrocarbon price-sensitive derivative instruments ("hydrocarbon
derivatives"), such as futures contracts, swaps, collars and options to mitigate
its overall exposure to fluctuations in hydrocarbon commodity prices. The
Company may also enter into hydrocarbon derivatives to hedge contractual
delivery commitments and future crude oil and natural gas production against
price exposure. The Company also actively trades hydrocarbon derivatives,
primarily exchange regulated futures and options contracts, subject to internal
policy limitations.
The Company uses a variance-covariance value at risk model to assess the market
risk of its hydrocarbon derivatives. Value at risk represents the potential loss
in fair value the Company would experience on its hydrocarbon derivatives, using
calculated volatilities and correlations over a specified time period with a
given confidence level. The Company's 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 the Company's fixed price pre-paid crude oil and pre-paid
natural gas sales. The model also includes the Company's net interests in its
subsidiaries' crude oil and natural gas hydrocarbon derivatives and forward
sales contracts. Based upon the Company's risk model, the value at risk related
to hydrocarbon derivatives held for hedging purposes was approximately $37
million at September 30, 2003. The value at risk related to hydrocarbon
derivatives held for non-hedging purposes was approximately $1 million at
September 30, 2003.
In order to provide a more comprehensive view of the Company's commodity price
risk, a tabular presentation of open hydrocarbon derivatives is also provided.
The following table sets forth the future volumes and price ranges of
hydrocarbon derivatives held by the Company at September 30, 2003, along with
the fair values of those instruments.
-57-
Open Hydrocarbon Hedging Derivative Instruments (a)
(Thousands of dollars)
Fair Value Asset
2003 2004 2005 2006 2007-2008 (Liability) (b)(c)
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Futures Positions
Volume (MMBtu) (1,900,000) (6,840,000) 30,000 - - $ 14,976
Average price, per MMBtu $ 5.66 $ 5.84 $ 5.01
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Swap Positions
Pay fixed price
Volume (MMBtu) 5,514,500 16,205,000 8,793,000 7,218,000 14,459,000 $ 57,231
Average swap price, per MMBtu $ 4.77 $ 4.12 $ 2.84 $ 2.42 $ 2.50
Receive fixed price
Volume (MMBtu) 11,590,000 33,790,000 25,550,000 - - $ 18,321
Average swap price, per MMBtu $ 5.75 $ 5.28 $ 4.63
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Basis Swap Positions
Volume (MMBtu) - - - - - $ 22
Average price received, per MMBtu
Average price paid, per MMBtu
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Collar Positions
Volume (MMBtu) 5,666,000 268,500 - - - $ (3,032)
Average ceiling price, per MMBtu $ 4.50 $ 5.45
Average floor price, per MMBtu $ 3.77 $ 2.82
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Option
Call Volume (MMBtu) - - - - - $ (200)
Average Call price $ -
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Future position
Volume (Bbls) (2,460,000) (1,200,000) - - - $ 11,884
Average price, per Bbl $ 30.55 $ 29.37
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Option (Over The Counter)
Put Volume (Bbls) (400,000) (720,000) - - - $ 858
Average price, per Bbl $ 24.00 $ 20.00
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Collar Positions
Volume (Bbls) 437,000 810,000 - - - $ (1,607)
Average ceiling price, per Bbl $ 32.00 $ 28.16
Average floor price, per Bbl $ 27.15 $ 23.41
====================================================================================================================================
(a) Positions reflect long (short) volumes.
(b) Net claims against counterparties with non-investment grade credit ratings are immaterial.
(c) Includes $4,948 thousand in assumed liabilities which were capitalized as acquisition costs.
-58-
Open Hydrocarbon Non-Hedging Derivative Instruments (a)
(Thousands of dollars)
2003 2004 Fair Value Asset
(Liability) (b)
--------------- --------------- ------------------------
Natural Gas Futures Positions
Volume (MMBtu) 1,320,000 - $(2,402)
Average price, per MMBtu $ 5.35
------------------------------------------------------------------------------------------------
Natural Gas Swap Positions
Pay fixed price
Volume (MMBtu) 1,215,000 - $(2,694)
Average swap price, per MMBtu $ 5.25
Receive fixed price
Volume (MMBtu) 1,084,088 95,438 $(2,098)
Average swap price, per MMBtu $ 5.16 $ 2.30
------------------------------------------------------------------------------------------------
Natural Gas Basis Swap Positions
Volume (MMBtu) 5,520,000 - $ 783
Average price received, per MMBtu $ 4.64
Average price paid, per MMBtu $ 4.54
------------------------------------------------------------------------------------------------
Natural Gas Spread Swap Positions
Volume (MMBtu) 1,985,000 3,040,000 $ 3,965
Average price received, per MMBtu $ 0.99 $ 0.38
Average price paid, per MMBtu $ 0.72 $ 1.51
------------------------------------------------------------------------------------------------
Natural Gas Option (Listed & OTC)
Call Volume (MMBtu) 5,150,000 - $ (473)
Average Call price $ 6.10
Call Volume (MMBtu) (15,990,000) (1,940,000) $ 5,020
Average Call price $ 6.05 $ 5.79
Put Volume (MMBtu) 4,480,000 4,870,000 $(1,340)
Average Put Price $ 4.62 $ 4.09
Put Volume (MMBtu) (10,910,000) (455,000) $ 2,128
Average Put Price $ 4.41 $ 4.30
------------------------------------------------------------------------------------------------
Natural Gas Spread Option (Over the Counter)
NYMEX / IFERC (c)
Call Volume (MMBtu) (300,000) (470,000) $ 0
Average Strike price $ 0.75 $ 2.00
Put Volume (MMBtu) (1,000,000) - $ 25
Average Strike price $ 0.25 $ -
------------------------------------------------------------------------------------------------
Crude Oil Future position
Volume (Bbls) 100,000 - $ (52)
Average price, per Bbl $ 28.34
------------------------------------------------------------------------------------------------
Crude Oil Option
Call Volumes (Bbls) 1,135,000 - $ (165)
Average price, per Bbl $ 32.77
Call Volumes (Bbls) (600,000) - $ 227
Average price, per Bbl $ 33.00
Put Volume (Bbls) 700,000 - $ (171)
Average price, per Bbl $ 27.64
Put Volume (Bbls) (700,000) - $ 156
Average price, per Bbl $ 27.07
------------------------------------------------------------------------------------------------
Crude Oil Swap Positions
Pay fixed price
Volume (Bbls) 1,450,000 2,300,000 $ (507)
Average swap price, per Bbl $ 27.49 26.13
Receive fixed price
Volume (Bbls) 1,450,000 2,500,001 $ 999
Average swap price, per Bbl $ 27.06 $ 25.78
------------------------------------------------------------------------------------------------
(a) Positions reflect long (short) volumes.
(b) Includes $3,464 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).
-59-
ITEM 4. CONTROLS AND PROCEDURES
As of the end of the period covered by this report, the Company carried out an
evaluation of the effectiveness of the design and operation of the Company's
disclosure controls and procedures pursuant to Rule 13a-15(e) of the Securities
Exchange Act of 1934. Based upon that evaluation, the Chief Executive Officer
and Chief Financial Officer concluded that the Company's disclosure controls and
procedures are effective in timely identifying material information potentially
required to be included in the Company's SEC filings.
There was no change in the Company's internal control over financial reporting
that occurred during the third quarter of 2003 that has materially affected, or
is reasonably likely to materially affect, the Company's internal control over
financial reporting.
Section 404 of the Sarbanes-Oxley Act of 2002 will require the Company to
include an internal control report with its 2004 annual report on Form 10-K. The
internal control report must assert (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. The Company's auditors will, in 2004, be
required to audit, and report on, these assertions. In order to achieve
compliance with Section 404 within the statutory period, management has formed a
steering committee and adopted a detailed project work plan to assess the
adequacy of the Company's internal controls, remediate any control weaknesses
that may be identified and validate through testing that controls are
functioning as documented. As a result of this initiative, the Company may make
changes in its internal controls from time to time during the period prior to
December 31, 2004.
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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 the Company previously reported in Item 3 of Unocal's Annual
Report on Form 10-K for the year ended December 31, 2002, and in Item 1 of Part
II of Unocal's Quarterly Report on Form 10-Q for the quarterly periods ended
March 31 and June 30, 2003. There is incorporated by reference: the information
regarding the environmental remediation reserve and possible additional
remediation costs in notes 16 and 17 to the consolidated financial statements in
Item 1 of Part I of this report; the discussion of such amounts in the
Environmental Matters section of Management's Discussion and Analysis in Item 2
of Part I; and the information regarding certain litigation and claims, tax
matters and other contingent liabilities in note 17 to the consolidated
financial statements.
Certain Environmental Matters Involving Civil Penalties
The Environmental Protection Agency ("EPA") and Unocal have entered into civil
settlements regarding the EPA's claims that Unocal violated the National
Pollutant Discharge Elimination System (NPDES) general permit concerning the
discharge of produced water and sanitary wastes into the Cook Inlet. On May 8,
2003, Unocal and the EPA executed Consent Agreements with respect to alleged
violations at 11 facilities. The settlements were subject to public comment
before final approval. On September 29, 2003, the Consent Agreements for ten
facilities received final approval, after those for three facilities were
amended to incorporate an additional 120 alleged violations. Unocal and the EPA
have entered into an amended Consent Agreement for one facility which remains
subject to public comment before final approval. The outstanding Consent
Agreement has been amended to incorporate an additional 61 alleged violations.
Most of the additional alleged violations include a monthly reporting period,
and therefore qualify as violations for each day of the entire standard 30-day
month. The total amount of the fine imposed pursuant to the settlements is
$531,875, of which Unocal will pay $327,991 and the remainder will be paid by
other working interest owners in the affected facilities.
ITEM 5. OTHER INFORMATION.
Effective October 1, 2003, the Company's Board of Directors named Samuel H.
Gillespie III as senior vice president, chief legal officer and general counsel.
Mr. Gillespie succeeds Charles O. Strathman and Timothy H. Thomas who had been
serving as chief legal officer and general counsel, respectively, on an interim
basis. Both Messrs. Strathman and Thomas will resume their former positions
as vice president, Law, during a transition period over the next several
months. Mr. Gillespie was also named as Corporate Secretary, succeeding
Brigitte M. Dewez. Mr. Gillespie joins Unocal from the Washington, D.C.,
office of the law firm of Skadden, Arps, Slate, Meagher and Flom, where he
advised energy clients and worked on a variety of international projects.
Previously, he was senior vice president and general counsel with Mobil
Corporation.
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ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits: The Exhibit Index on page 64 of this report lists the
exhibits that are filed as part of this report.
(b) Reports on Form 8-K:
Filed during the third quarter of 2003:
(1) Current Report on Form 8-K, dated and filed July 14, 2003,
for the purpose of reporting, under Item 5, the Company's
agreement to sell its rights and interest in the Sarulla
geothermal project on the island of Sumatra in Indonesia.
(2) Current Report on Form 8-K, dated July 15, 2003, and filed
July 16, 2003, for the purpose of reporting, under Item 5
and Item 7, the Company's filing of an amended Schedule 13D
with respect to the Company's interest in Tom Brown, Inc.
(3) Current Report on Form 8-K, dated July 23, 2003, and filed
July 24, 2003, for the purpose of reporting, under Item 5,
the Company's discovery on the deepwater Gehem prospect,
offshore East Kalimantan, Indonesia.
(4) Current Report on Form 8-K, dated July 29, 2003, and filed
July 31, 2003, for the purpose of reporting, under Item 5,
the Company's second quarter and six months earnings
results, other related information and the Company's 2003
outlook.
(5) Current Report on Form 8-K, dated September 16, 2003, and
filed September 18, 2003, for the purpose of reporting,
under Item 5, the Company's sale of common shares held in
Tom Brown, Inc.
(6) Current Report on Form 8-K, dated September 21, 2003, and
filed September 23, 2003, for the purpose of reporting,
under Item 5, the Company agreement to sell 70 properties in
the Gulf of Mexico and onshore Louisiana to Forest Oil
Corporation.
Filed during the fourth quarter of 2003 to the date hereof:
(1) Current Report on Form 8-K, dated October 3, 2003, and filed
October 6, 2003, for the purpose of reporting, under Item 5,
the Company's production forecast for the third and fourth
quarters of 2003.
(2) Current Report on Form 8-K, dated October 29, 2003, and
filed November 3, 2003, for the purpose of reporting under
Item 5, the Company's third quarter and nine months earnings
results, other related information, the Company's outlook
for the remainder of 2003 and a discovery in the deepwater
Gulf of Mexico.
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
UNOCAL CORPORATION
(Registrant)
Dated: November 14, 2003 By: /s/JOE D. CECIL
---------------------
Joe D. Cecil
Vice President and Comptroller
(Duly Authorized Officer and
Principal Accounting Officer)
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EXHIBIT INDEX
10 Employment Agreement, effective as of October 1, 2003, by and between
Unocal and Samuel H. Gillespie III.
12.1 Statement regarding computation of ratio of earnings to fixed
charges of Unocal Corporation for the nine months ended
September 30, 2003 and 2002.
12.2 Statement regarding computation of ratio of earnings to fixed charges
of Union Oil Company of California for the nine months ended
September 30, 2003 and 2002.
31 Certifications Pursuant to 18 U.S.C Section 1350, as Adopted Pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002.
32 Certifications Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.
Copies of exhibits will be furnished upon request. Requests should
be addressed to the Corporate Secretary.
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