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 June 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
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Commission file number 1-8483
UNOCAL CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 95-3825062
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2141 ROSECRANS AVENUE, SUITE 4000, EL SEGUNDO, CALIFORNIA 90245
(Address of principal executive offices)
(Zip Code)
(310) 726-7600
(Registrant's Telephone Number, Including Area Code)
Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
------- -------
Indicate by check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Act). Yes X No
------- -------
Number of shares of Common Stock, $1 par value, outstanding as of
July 31, 2003: 258,344,422
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....................... 34
Operating Highlights ............................................... 36
Item 3. Quantative and Qualitative Disclosures About Market Risk............ 49
Item 4. Controls and Procedures............................................. 53
PART II OTHER INFORMATION
Item 1. Legal Proceedings................................................... 54
Item 4. Submission of Matters to a Vote of Security Holders................. 55
Item 6. Exhibits and Reports on Form 8-K.................................... 56
SIGNATURE................................................................... 57
EXHIBIT INDEX............................................................... 58
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 Six Months
Ended June 30, Ended June 30,
------------------------------------------
Millions of dollars except
per share amounts 2003 2002 2003 2002
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Revenues
Sales and operating revenues $ 1,564 $ 1,361 $ 3,339 $ 2,396
Interest, dividends and
miscellaneous income (loss) 9 8 20 20
Gain (loss) on sales of assets 47 (1) 50 1
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Total revenues 1,620 1,368 3,409 2,417
Costs and other deductions
Crude oil, natural gas
and product purchases 536 428 1,182 723
Operating expense 325 324 619 623
Administrative and general expense 87 37 138 80
Depreciation, depletion and amortization 255 255 515 479
Asset impairments 3 21 3 21
Dry hole costs 10 13 81 41
Exploration expense 88 61 143 120
Interest expense 36 43 74 94
Property and other operating taxes 21 18 43 34
Distributions on convertible preferred
securities of subsidiary trust 8 8 16 16
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Total costs and other deductions 1,369 1,208 2,814 2,231
Earnings from equity investments 53 51 96 88
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Earnings from continuing operations before
income taxes and minority interests 304 211 691 274
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Income taxes 133 95 301 135
Minority interests 2 3 4 4
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Earnings from continuing operations 169 113 386 135
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Earnings from discontinued operations 8 1 8 1
Cumulative effects of accounting changes (a) - - (83) -
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Net earnings $ 177 $ 114 $ 311 $ 136
================================================================================
Basic earnings per share of common stock (b)
Continuing operations $ 0.66 $ 0.46 $ 1.50 $ 0.55
Net earnings $ 0.69 $ 0.46 $ 1.21 $ 0.55
Diluted earnings per share of common stock (c)
Continuing operations $ 0.65 $ 0.46 $ 1.47 $ 0.55
Net earnings $ 0.68 $ 0.46 $ 1.20 $ 0.55
Cash dividends declared per share
of common stock $ 0.20 $ 0.20 $ 0.40 $ 0.40
--------------------------------------------------------------------------------
(a) Net of tax (benefit) $ - $ - $ (48) $ -
(b) Basic weighted average shares
outstanding (in thousands) 258,202 244,639 258,103 244,423
(c) Diluted weighted average shares
outstanding (in thousands) 272,108 245,865 271,907 245,531
See Notes to the Consolidated Financial Statements.
-1-
CONSOLIDATED BALANCE SHEET UNOCAL CORPORATION
At June 30, At December 31,
----------------------------------
Millions of dollars 2003 (a) 2002
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Assets
Current assets
Cash and cash equivalents $ 363 $ 168
Accounts and notes receivable - net 1,000 994
Inventories 101 97
Deferred income taxes 120 90
Other current assets 32 26
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Total current assets 1,616 1,375
Investments and long-term receivables - net 1,074 1,044
Properties - net (b) 8,327 7,879
Goodwill 129 122
Deferred income taxes 247 210
Other assets 143 130
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Total assets $ 11,536 $ 10,760
================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ 1,050 $ 1,024
Taxes payable 220 223
Dividends payable 51 51
Interest payable 45 50
Current portion of environmental liabilities 121 113
Current portion of long-term debt
and capital leases 232 6
Other current liabilities 176 165
--------------------------------------------------------------------------------
Total current liabilities 1,895 1,632
Long-term debt and capital leases 2,744 3,002
Deferred income taxes 677 593
Accrued abandonment, restoration
and environmental liabilities 917 622
Other deferred credits and liabilities 860 816
Minority interests 276 275
Commitments and contingencies - Note 13
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 973 962
Unearned portion of restricted stock issued (16) (20)
Retained earnings 3,229 3,021
Accumulated other comprehensive income (364) (486)
Notes receivable - key employees (35) (37)
Treasury stock - at cost (d) (411) (411)
--------------------------------------------------------------------------------
Total stockholders' equity 3,645 3,298
--------------------------------------------------------------------------------
Total liabilities and stockholders' equity $ 11,536 $ 10,760
================================================================================
(a) Unaudited
(b) Net of accumulated depreciation,
depletion and amortization of: $ 12,745 $ 12,277
(c) Number of shares outstanding
(in thousands) 258,323 257,980
(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 Six Months
Ended June 30,
---------------------------------
Millions of dollars 2003 2002
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Cash Flows from Operating Activities
Net earnings $ 311 $ 136
Adjustments to reconcile net earnings to
net cash provided by operating activities
Depreciation, depletion and amortization 515 479
Asset impairments 3 21
Dry hole costs 81 41
Amortization of exploratory leasehold costs 71 45
Deferred income taxes 40 (17)
Gain on sales of assets (50) (1)
Gain on disposal of discontinued operations (13) (2)
Pension expense 42 13
Restructuring provisions net of payments 27 19
Cumulative effect of accounting changes 83 -
Other 41 (72)
Working capital and other changes
related to operations
Accounts and notes receivable 6 18
Inventories (4) (9)
Accounts payable 26 (1)
Taxes payable (3) (4)
Other (91) (40)
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Net cash provided by operating activities 1,085 626
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Cash Flows from Investing Activities
Capital expenditures (includes dry hole costs) (917) (830)
Proceeds from sales of assets 191 45
Proceeds from sale of discontinued operations - 2
--------------------------------------------------------------------------------
Net cash used in investing activities (726) (783)
--------------------------------------------------------------------------------
Cash Flows from Financing Activities
Long-term borrowings 79 440
Reduction of long-term debt and
capital lease obligations (143) (229)
Minority interests (3) (4)
Proceeds from issuance of common stock 10 19
Dividends paid on common stock (103) (98)
Other (4) -
--------------------------------------------------------------------------------
Net cash provided by (used in) financing activities (164) 128
--------------------------------------------------------------------------------
Net increase (decrease) in cash and cash equivalents 195 (29)
--------------------------------------------------------------------------------
Cash and cash equivalents at beginning of year 168 190
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Cash and cash equivalents at end of period $ 363 $ 161
================================================================================
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized) $ 83 $ 95
Income taxes (net of refunds) $ 275 $ 171
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 six months ended June 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 $9 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 June 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 For the years For the Six
Millions of dollars ended December 31, Months Ended
(except per share amounts) 2000 2001 2002 June 30, 2002
--------------------------------------------------------------------------------
Net income as reported $760 $615 $331 $136
Earnings per share as reported:
Basic $3.13 $2.52 $1.34 $0.55
Diluted $3.08 $2.50 $1.34 $0.55
Pro forma net income $740 $596 $312 $126
Pro forma earnings per share:
Basic $3.05 $2.44 $1.26 $0.52
Diluted $3.00 $2.42 $1.26 $0.52
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 7 for further details). This change is estimated to decrease 2003
after-tax income by approximately $5 million. When fully phased in for future
grants over the next three years, the annual after-tax expense is estimated to
be approximately $10 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: In April 2003, the FASB issued 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. SFAS No. 149 is effective for contracts entered into or
modified after June 30, 2003. The Company does not expect the adoption of SFAS
No. 149 to have a significant impact on its 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 14. 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 companies defined as
variable interest entities. This Interpretation is effective for new variable
interest entities as of February 1, 2003. The effective date for the
consolidation of entities existing prior to February 1, 2003 is July 1, 2003.
The Company has included the disclosure requirements of the Interpretation in
this report and expects the adoption of the recognition (i.e., consolidation)
requirements of the Interpretation to increase its consolidated long-term debt
by approximately $78 million in the third quarter of 2003. This amount reflects
third-party debt related to Dayabumi Salak Pratama, Ltd. ("DSPL"), an equity
investee that sells electricity generated from geothermal steam in Indonesia
(see note 12 for further details). An additional $242 million, currently
classified as minority interests, 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 (see notes 12 and 18 for further detail).
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.
-6-
3. Other Financial Information
During the second quarters of 2003 and 2002, approximately 25 percent and 23
percent, respectively, of total sales and operating revenues were attributable
to the resale of liquids and natural gas purchased from others in connection
with marketing activities. For the six months ended June 30, 2003 and 2002,
these percentages were approximately 25 percent and 22 percent, respectively.
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 $19 million and $10 million for the second quarters
of 2003 and 2002, respectively. For the six months ended June 30, 2003 and 2002,
capitalized interest totaled $35 million and $19 million, respectively. The
increase was primarily due to the capitalized interest related to the West Seno
oil and gas development project in the deepwater Kutei Basin, offshore East
Kalimantan, Indonesia, and 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 Six Months
Ended June 30 Ended June 30
------------------------- -------------------------
Millions of dollars 2003 2002 2003 2002
--------------------------------------------------------------------------------
Exploration operations $ 16 $ 25 $ 31 $ 48
Geological and geophysical 20 8 34 19
Amortization of exploratory
leasehold costs 47 23 71 45
Leasehold rentals 5 5 7 8
--------------------------------------------------------------------------------
Exploration expense $ 88 $ 61 $ 143 $ 120
================================================================================
Amortization of exploratory leasehold costs included a $26 million pre-tax
provision that was a result of the Company's intention to relinquish about 45
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.
4. Restructuring
In June 2003, the Company adopted a restructuring plan that resulted in the
accrual of a $27 million pre-tax restructuring charge. The charge included the
estimated costs of terminating 219 employees. The plan involves the streamlining
of the organizational structures in order to align them with the Company's
portfolio requirements and business needs. Approximately 37 of the affected
employees are from various exploration and production business units and 182 are
from other organizations, including corporate staff. The restructuring charge
included approximately $21 million for termination costs to be paid to the
employees over time, approximately $2 million for outplacement and other costs
and $4 million for pension and post retirement expenses. The restructuring
charge is included in selling, administrative and general expense on the
consolidated earnings statement. At June 30, 2003, 51 employees had been
terminated or had received termination notices as a result of the plan, with
additional notifications to be made in the third quarter. The majority of these
restructuring costs will be paid in 2004.
In 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 June 30, 2003, approximately
$17 million of the restructuring costs had been paid and charged against the
liability, leaving accrued costs of $2 million on the consolidated balance sheet
at June 30, 2003. The remaining costs are expected to be paid by the end of
2003.
-7-
Also in 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 June 30, 2003.
Approximately $2 million of the restructuring costs had been paid and charged
against the liability, leaving accrued costs of $2 million on the consolidated
balance sheet at June 30, 2003. The remaining costs are expected to be paid
during 2003 and the first half of 2004.
5. Income Taxes
Income taxes on earnings from continuing operations for the second quarter and
six months periods of 2003 were $133 million and $301 million, respectively,
compared with $95 million and $135 million for the comparable periods of 2002.
The effective income tax rate for both the second quarter and six months periods
of 2003 was 44 percent, compared with 45 percent and 49 percent for the
comparable periods of 2002. The lower effective tax rate in 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. Foreign
earnings are generally taxed at higher rates.
6. Earnings Per Share
The following are reconciliations of the numerators and denominators of the
basic and diluted earnings per share ("EPS") computations for earnings from
continuing operations for the second quarters and six months ended June 30, 2003
and 2002:
--------------------------------------------------------------------------------
Earnings Shares Per Share
Millions except per share amounts (Numerator) (Denominator) Amount
--------------------------------------------------------------------------------
Three months ended June 30, 2003
Earnings from continuing operations $ 169 258.2
Basic EPS $ 0.66
=========
Effect of dilutive securities
Options and common stock equivalents 1.6
---------------------------
169 259.8 $ 0.65
Distributions on subsidiary trust
preferred securities (after-tax) 7 12.3
---------------------------
Diluted EPS $ 176 272.1 $ 0.65
=========
Three months ended June 30, 2002
Earnings from continuing operations $ 113 244.6
Basic EPS $ 0.46
=========
Effect of dilutive securities
Options and common stock equivalents 1.2
---------------------------
Diluted EPS 113 245.8 $ 0.46
=========
Distributions on subsidiary trust
preferred securities (after-tax) 7 12.3
---------------------------
Antidilutive $ 120 258.1 $ 0.46
--------------------------------------------------------------------------------
Not included in the computation of diluted EPS for the three months ended June
30, 2003 and 2002, were options outstanding to purchase approximately 8.9
million and 1.9 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.
-8-
--------------------------------------------------------------------------------
Earnings Shares Per Share
Millions except per share amounts (Numerator) (Denominator) Amount
--------------------------------------------------------------------------------
Six months ended June 30, 2003
Earnings from continuing operations $ 386 258.1
Basic EPS $ 1.50
=========
Effect of dilutive securities
Options and common stock equivalents 1.5
---------------------------
386 259.6 $ 1.49
Distributions on subsidiary trust
preferred securities (after-tax) 14 12.3
---------------------------
Diluted EPS $ 400 271.9 $ 1.47
=========
Six months ended June 30, 2002
Earnings from continuing operations $ 135 244.4
Basic EPS $ 0.55
=========
Effect of dilutive securities
Options and common stock equivalents 1.1
---------------------------
Diluted EPS 135 245.5 $ 0.55
=========
Distributions on subsidiary trust
preferred securities (after-tax) 14 12.3
---------------------------
Antidilutive $ 149 257.8 $ 0.58
--------------------------------------------------------------------------------
Not included in the computation of diluted EPS for the six months ended June 30,
2003 and 2002, were options outstanding to purchase approximately 10.5 million
and 3.3 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 Six Months
Ended June 30, Ended June 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 $ 8 $ 1
Weighted average common shares outstanding 258.2 244.6 258.1 244.4
Earnings from discontinued operations $ 0.03 $ - $ 0.03 $ -
Dilutive earnings per share of common stock:
Discontinued operations:
Earnings from discontinued operations $ 8 $ 1 $ 8 $ 1
Weighted average common shares outstanding 272.1 245.9 271.9 245.5
Earnings from discontinued operations $ 0.03 $ - $ 0.03 $ -
--------------------------------------------------------------------------------
-9-
7. 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 For the
Three Months Six Months
Ended June 30, Ended June 30,
---------------------------------
Millions of dollars except per share amounts 2003 2002 2003 2002
--------------------------------------------------------------------------------
Net earnings
As reported $ 177 $ 114 $ 311 $136
Add: Stock-based employee compensation
expense included in reported net
income, net of related tax effects
and minority interests 4 1 6 8
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 (6) (7) (10) (19)
---------------------------------
Pro forma net earnings $ 175 $ 108 $ 307 $ 125
=================================
Net earnings per share:
Basic - as reported $ 0.69 $ 0.46 $ 1.21 $ 0.55
Basic - pro forma $ 0.68 $ 0.44 $ 1.19 $ 0.51
Diluted - as reported $ 0.68 $ 0.46 $ 1.20 $ 0.55
Diluted - pro forma $ 0.67 $ 0.44 $ 1.18 $ 0.51
8. Comprehensive Income
The Company's comprehensive income was:
For the For the
Three Months Six Months
Ended June 30, Ended June 30,
---------------------------------
Millions of dollars 2003 2002 2003 2002
--------------------------------------------------------------------------------
Net earnings $ 177 $ 114 $ 311 $ 136
Change in unrealized loss
on hedging instruments (a) 7 (1) (3) (9)
Reclassification adjustment for settled
hedging contracts (b) 4 4 11 (1)
Unrealized foreign currency
translation adjustments 68 35 114 32
--------------------------------------------------------------------------------
Total comprehensive income $ 256 $ 152 $ 433 $ 158
================================================================================
(a) Net of tax effect of: 4 (1) (2) (5)
(b) Net of tax effect of: 2 2 6 (1)
-10-
9. Cash and Cash Equivalents
At June 30, At December 31,
---------------------------------
Millions of dollars 2003 2002
--------------------------------------------------------------------------------
Cash $ 119 $ 58
Time deposits 112 110
Restricted cash 1 -
Marketable securities 131 -
--------------------------------------------------------------------------------
Cash and cash equivalents $ 363 $ 168
================================================================================
The marketable securities at June 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.
10. Assets Held for Sale
The Company announced that it has initiated a divestiture program that will
involve approximately 100 fields in the Gulf of Mexico shelf and onshore,
including associated pipelines. The Company is currently in the process of
marketing the properties for sale to several potential buyers.
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 third
quarter of 2003, and the Company expects to record a gain on the transaction.
Details of the assets and liabilities for the assets classified as held for
sale, as of June 30, 2003, are presented below:
U.S.
Millions of dollars Lower 48 Midstream Geothermal Total
--------------------------------------------------------------------------------
Assets
Properties - net (b) $ 391 $ 7 $ 26 $ 424
Other assets 8 - - 8
--------------------------------------------------------------------------------
Total assets $ 399 $ 7 $ 26 $ 432
================================================================================
Liabilities
Accrued abandonment, restoration
and environmental liabilities $ 94 $ - $ - 94
Other deferred credits and liabilities 6 - - 6
--------------------------------------------------------------------------------
Total liabilities $ 100 $ - $ - $ 100
================================================================================
11. Long Term Debt and Credit Agreements
During the first six months of 2003, the Company's consolidated debt, including
the current portion, decreased by $32 million. 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 and repaid $20 million of 6.20%
Industrial Development Revenue Bonds.
These decreases were partially offset by $79 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 $300 million for the first phase, and
the other loan is $50 million for the second phase. The second phase loan will
be subject to further due diligence by the lender. This initial draw down has a
floating rate that is adjusted weekly, which as of June 30, 2003, was set at
1.15%.
-11-
At June 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 $218
million, using applicable foreign exchange rates, or a $32 million increase from
year-end 2002.
12. 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 $82 million at June 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), will require the Company to consolidate DSPL,
resulting in the reporting of $78 million as long-term debt on the consolidated
balance sheet at that time. At June 30, 2003, the Company's maximum exposure to
loss as a result of its involvement with DSPL was approximately $95 million.
An additional $242 million, currently classified as minority interests, related
to a partnership interest in Spirit LP, would have been required to be
consolidated as long-term debt under FASB Interpretation No. 46 had it not been
paid in July 2003 (see note 18 for further detail).
13. 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 June 30, 2003, the Company had accrued
$758 million and $771 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 $22 million.
This accrual was partially offset by abandonment liability settlements of $9
million completed during the period. There were no material abandonment and
restoration liabilities incurred or revisions in abandonment and restoration
cost estimates during the first six months of 2003. The Company's total accrued
abandonment and restoration liabilities of $771 million at June 30, 2003,
include $94 million in abandonment liabilities associated with assets held for
sale (see note 10 for further detail).
The Company's reserve for environmental remediation obligations at June 30, 2003
totaled $267 million, of which $121 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. 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.
-12-
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 13, at June 30, 2003, the Company had accrued $267 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 $205 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.
The accrued costs and the possible additional costs are shown below for four
categories of sites:
At June 30, 2003
----------------------------
Possible
Additional
Millions of dollars Reserve Costs
--------------------------------------------------------------------------------
Superfund and similar sites $ 17 $ 15
Active Company facilities 31 25
Company facilities sold with retained liabilities
and former Company-operated sites 98 80
Inactive or closed Company facilities 121 85
--------------------------------------------------------------------------------
Total $ 267 $ 205
================================================================================
-13-
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.
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 June 30, 2003, Unocal had received notifications from the U.S. Environmental
Protection Agency ("EPA") that the Company may be a PRP at 23 sites and may
share certain liabilities at these sites. Of the total, four sites are under
investigation and/or litigation and the Company's potential liability is not
presently determinable and at two sites the Company's potential liability
appears to be de minimis. Of the remaining 17 sites, where the Company has
concluded that liability is probable and to the extent costs can be reasonably
estimated, a reserve of $13 million has been established for future remediation
and settlement costs.
-14-
Various state agencies and private parties had identified 21 other similar PRP
sites. Four sites are under investigation and/or litigation and the Company's
potential liability is not presently determinable and for two sites, the Company
has denied responsibility. At two 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 13
sites, a reserve of $4 million has been established for future remediation and
settlement costs.
The sites discussed above exclude 121 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 $31 million for estimated future costs of remedial
orders, corrective actions and other investigation, remediation and monitoring
obligations at certain operating facilities and producing oil and gas fields.
The Company made payments of $7 million for this category of sites in the first
six 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.
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 $98 million for this group of sites.
During the first six months of 2003, provisions of $9 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. 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 $15 million were made during the first six months of 2003 for sites
in this category.
-15-
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 $121 million has been established for these types of facilities.
During the first six months of 2003, the Company recorded provisions of $40
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 six 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 $7 million were made during the first six 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.
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
June 30, 2003, amounts in the remediation reserve for these facilities totaled
$124 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.
-16-
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.
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. 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.
-17-
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").
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.
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.
The Company believes that certain portions of its disputes with Agrium are
subject to binding arbitration under the terms of the GPSA. The Company
initiated the Arbitration to determine the amount and delivery rate of the
remaining gas supply available under that agreement. Agrium claims the dispute
resolution provisions of the PSA supersede the arbitration provisions of the
GPSA. On July 16, 2003, the court approved an agreed stipulation between the
parties to submit all issues under the GPSA to arbitration. 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.
-18-
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.
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.
-19-
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 under examination by the Internal Revenue Service.
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 June 30, 2003, the reserve for this
category totaled $98 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 $21 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.
-20-
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 June 30, 2003, the
Company had obtained various surety bonds for approximately $217 million. These
surety bonds included a bond for $86 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 $131 million in various other routine
performance bonds held by local, city, state and federal agencies. The Company
also had obtained approximately $38 million in standby letters of credit at June
30, 2003. 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 $170 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 27 months at June 30, 2003.
The drillship has a current minimum daily rate of approximately $224,000. The
future remaining minimum lease payment obligation was approximately $182 million
at June 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.
-21-
15. 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 June 30, 2003, including the current portion,
was approximately $3.39 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 $501 million at June 30, 2003. The fair value was
based on the closing trading price of the preferred securities on June 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 second quarter and six months periods ended June
30, 2003. At June 30, 2003, the Company had approximately $15 million of
after-tax deferred losses in accumulated other comprehensive income on the
consolidated balance sheet related to cash flow hedges for future commodity
sales for the period beginning July 2003 through December 2004. Of this amount,
approximately $13 million in after-tax losses are expected to be reclassified to
the consolidated earnings statement during the next twelve months.
Foreign currency contracts - At June 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. All of this
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 June 30, 2003, the Company had approximately $24 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.
-22-
16. 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 June 30, 2003
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-----------------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ - $ 361 $ 1,525 $ (322) $ 1,564
Interest, dividends and miscellaneous income - 9 7 4 (11) 9
Gain on sales of assets - - 43 4 - 47
-----------------------------------------------------------------------------------------------------------------------------
Total revenues - 9 411 1,533 (333) 1,620
Costs and other deductions
Purchases, operating and other expenses 3 - 341 1,036 (323) 1,057
Depreciation, depletion and amortization - - 78 177 - 255
Impairments - - 3 - - 3
Dry hole costs - - 6 4 - 10
Interest expense 9 1 29 7 (10) 36
Distributions on convertible preferred securities - 8 - - - 8
-----------------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 12 9 457 1,224 (333) 1,369
Equity in earnings of subsidiaries 187 - 224 - (411) -
Earnings from equity investments - - 4 49 - 53
-----------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 175 - 182 358 (411) 304
-----------------------------------------------------------------------------------------------------------------------------
Income taxes (2) - 3 132 - 133
Minority interests - - - 2 - 2
-----------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 177 - 179 224 (411) 169
Earnings from discontinued operations - - 8 - - 8
-----------------------------------------------------------------------------------------------------------------------------
Net earnings $ 177 $ - $ 187 $ 224 $ (411) $ 177
=============================================================================================================================
-23-
CONDENSED CONSOLIDATED EARNINGS STATEMENT
Three months ended June 30, 2002
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-----------------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ - $ 286 $ 1,310 $ (235) $ 1,361
Interest, dividends and miscellaneous income - 9 - 10 (11) 8
Gain on sales of assets - - 1 (2) - (1)
-----------------------------------------------------------------------------------------------------------------------------
Total revenues - 9 287 1,318 (246) 1,368
Costs and other deductions
Purchases, operating and other expenses 1 - 259 848 (240) 868
Depreciation, depletion and amortization - - 93 162 - 255
Impairments - - 21 - - 21
Dry hole costs - - 2 11 - 13
Interest expense 9 1 35 9 (11) 43
Distributions on convertible preferred securities - 8 - - - 8
-----------------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 10 9 410 1,030 (251) 1,208
Equity in earnings of subsidiaries 118 - 198 - (316) -
Earnings from equity investments - - 2 49 - 51
-----------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 108 - 77 337 (311) 211
-----------------------------------------------------------------------------------------------------------------------------
Income taxes (3) - (41) 139 - 95
Minority interests - - - 1 2 3
-----------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 111 - 118 197 (313) 113
Earnings from discontinued operations - - - 1 - 1
Cumulative effects of accounting changes - - - - - -
-----------------------------------------------------------------------------------------------------------------------------
Net earnings $ 111 $ - $ 118 $ 198 $ (313) $ 114
=============================================================================================================================
-24-
CONDENSED CONSOLIDATED EARNINGS STATEMENT
For the six months ended June 30, 2003
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-----------------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ - $ 873 $ 3,215 $ (749) $ 3,339
Interest, dividends and miscellaneous income - 17 18 6 (21) 20
Gain on sales of assets - - 34 16 - 50
-----------------------------------------------------------------------------------------------------------------------------
Total revenues - 17 925 3,237 (770) 3,409
Costs and other deductions
Purchases, operating and other expenses 5 - 623 2,247 (750) 2,125
Depreciation, depletion and amortization - - 184 331 - 515
Impairments - - 3 - - 3
Dry hole costs - - 58 23 - 81
Interest expense 17 1 59 17 (20) 74
Distributions on convertible preferred securities - 16 - - - 16
-----------------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 22 17 927 2,618 (770) 2,814
Equity in earnings of subsidiaries 329 - 435 - (764) -
Earnings from equity investments - - 7 89 - 96
-----------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 307 - 440 708 (764) 691
-----------------------------------------------------------------------------------------------------------------------------
Income taxes (4) - 34 271 - 301
Minority interests - - - 4 - 4
-----------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 311 - 406 433 (764) 386
Earnings from discontinued operations - - 8 - - 8
Cumulative effects of accounting changes - - (85) 2 - (83)
-----------------------------------------------------------------------------------------------------------------------------
Net earnings $ 311 $ - $ 329 $ 435 $ (764) $ 311
=============================================================================================================================
-25-
CONDENSED CONSOLIDATED EARNINGS STATEMENT
For the six months ended June 30, 2002
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-----------------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ - $ 495 $ 2,302 $ (401) $ 2,396
Interest, dividends and miscellaneous income - 17 7 15 (19) 20
Gain on sales of assets - - 14 (13) - 1
-----------------------------------------------------------------------------------------------------------------------------
Total revenues - 17 516 2,304 (420) 2,417
Costs and other deductions
Purchases, operating and other expenses 3 - 486 1,493 (402) 1,580
Depreciation, depletion and amortization - - 180 299 - 479
Impairments - - 21 - - 21
Dry hole costs - - 17 24 - 41
Interest expense 17 1 78 18 (20) 94
Distributions on convertible preferred securities - 16 - - - 16
-----------------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 20 17 782 1,834 (422) 2,231
Equity in earnings of subsidiaries 148 - 326 - (474) -
Earnings from equity investments - - 2 86 - 88
-----------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 128 - 62 556 (472) 274
-----------------------------------------------------------------------------------------------------------------------------
Income taxes (7) - (86) 228 - 135
Minority interests - - - 3 1 4
-----------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 135 - 148 325 (473) 135
Earnings from discontinued operations - - - 1 - 1
Cumulative effects of accounting changes - - - - - -
-----------------------------------------------------------------------------------------------------------------------------
Net earnings $ 135 $ - $ 148 $ 326 $ (473) $ 136
=============================================================================================================================
-26-
CONDENSED CONSOLIDATED BALANCE SHEET
At June 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 $ - $ - $ 150 $ 213 $ - $ 363
Accounts and notes receivable - net 59 - 260 751 (70) 1,000
Inventories - - 15 86 - 101
Other current assets - - 118 34 - 152
-----------------------------------------------------------------------------------------------------------------------------
Total current assets 59 - 543 1,084 (70) 1,616
Investments and long-term receivables - net 4,891 - 4,958 1,000 (9,775) 1,074
Properties - net - - 2,244 6,086 (3) 8,327
Other assets including goodwill 4 541 25 (55) 4 519
-----------------------------------------------------------------------------------------------------------------------------
Total assets $4,954 $ 541 $ 7,770 $ 8,115 $ ( 9,844) $ 11,536
=============================================================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ - $ - $ 262 $ 847 $ (59) $ 1,050
Current portion of long-term debt
and capital leases - - 215 17 - 232
Other current liabilities 51 3 296 276 (13) 613
-----------------------------------------------------------------------------------------------------------------------------
Total current liabilities 51 3 773 1,140 (72) 1,895
Long-term debt and capital leases - - 2,088 656 - 2,744
Deferred income taxes - - (150) 827 - 677
Accrued abandonment, restoration
and environmental liabilities - - 471 446 - 917
Other deferred credits and liabilities 541 - 459 (149) 9 860
Minority interests - - - 317 (41) 276
Company-obligated mandatorily redeemable
convertible preferred securities of a
subsidiary trust holding solely parent debentures - 522 - - - 522
Stockholders' equity 4,362 16 4,129 4,878 (9,740) 3,645
-----------------------------------------------------------------------------------------------------------------------------
Total liabilities and stockholders' equity $4,954 $ 541 $ 7,770 $ 8,115 $ ( 9,844) $ 11,536
=============================================================================================================================
-27-
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
=============================================================================================================================
-28-
CONDENSED CONSOLIDATED CASH FLOWS
For the six months ended June 30, 2003
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-----------------------------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities $ 93 $ - $ 389 $ 603 $ - $1,085
Cash Flows from Investing Activities
Capital expenditures and acquisitions
(includes dry hole costs) - - (223) (694) - (917)
Proceeds from sales of assets
and discontinued operations - - 123 68 - 191
-----------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities - - (100) (626) - (726)
-----------------------------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Change in long-term debt and capital leases - - (114) 50 - (64)
Dividends paid on common stock (103) - - - - (103)
Minority interests - - - (3) - (3)
Other 10 - (7) 3 - 6
-----------------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities (93) - (121) 50 - (164)
-----------------------------------------------------------------------------------------------------------------------------
Increase in cash and cash equivalents - - 168 27 - 195
-----------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at beginning of period - - (18) 186 - 168
-----------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ - $ - $ 150 $ 213 $ - $ 363
=============================================================================================================================
CONDENSED CONSOLIDATED CASH FLOWS
For the six months ended June 30, 2002
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-----------------------------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities $ 80 $ - $ (110) $ 656 $ - $ 626
Cash Flows from Investing Activities
Capital expenditures and acquisitions
(includes dry hole costs) - - (213) (617) - (830)
Proceeds from sales of assets
and discontinued operations - - 15 32 - 47
-----------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities - - (198) (585) - (783)
-----------------------------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Change in long-term debt and capital leases - - 307 (96) - 211
Dividends paid on common stock ( 98) - - - - ( 98)
Minority interests - - - (4) - (4)
Other 19 - - - - 19
-----------------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities (79) - 307 (100) - 128
-----------------------------------------------------------------------------------------------------------------------------
Increase (decrease) in cash and cash equivalents 1 - (1) (29) - (29)
-----------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at beginning of period - - 62 128 - 190
-----------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ 1 $ - $ 61 $ 99 $ - $ 161
=============================================================================================================================
-29-
17. 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 June 30, 2003
Millions of dollars U.S. Lower 48 Alaska Canada Far East Other
---------------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 141 $ 62 $ 37 $ 299 $ 88 $ 738
Other income (loss) (a) 46 - - - - -
Inter-segment revenues 284 - 41 72 - 1
---------------------------------------------------------------------------------------------------------------------------
Total 471 62 78 371 88 739
Earnings from equity investments 6 - - 10 1 -
Earnings (loss) from continuing operations 89 14 8 116 29 4
Earnings from discontinued operations - - - - - -
---------------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 89 14 8 116 29 4
---------------------------------------------------------------------------------------------------------------------------
Assets (at June 30, 2003) 3,245 329 1,318 3,018 896 364
---------------------------------------------------------------------------------------------------------------------------
Midstream Geothermal Corporate & Other Total
& Power
Operations Admin Net Interest Environmental
& General Expense & Litigation Other (b)
---------------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 128 $ 28 $ - $ - $ - $ 43 $ 1,564
Other income (loss) (a) 1 2 - 6 - 1 56
Inter-segment revenues 2 - - - - (400) -
---------------------------------------------------------------------------------------------------------------------------
Total 131 30 - 6 - (356) 1,620
Earnings from equity investments 17 4 - - - 15 53
Earnings (loss) from continuing operations 18 7 (22) (28) (28) (38) 169
Earnings from discontinued operations - - - - - 8 8
---------------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 18 7 (22) (28) (28) (30) 177
---------------------------------------------------------------------------------------------------------------------------
Assets (at June 30, 2003) 596 535 - - - 1,235 11,536
---------------------------------------------------------------------------------------------------------------------------
(a) Includes interest, dividends and miscellaneous income, and gain (loss) on sales of assets.
(b) Includes eliminations and consolidation adjustments.
-30-
Segment Information Exploration & Production Trade
For the Three Months North America International
ended June 30, 2002
Millions of dollars U.S. Lower 48 Alaska Canada Far East Other
---------------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 123 $ 73 $ 63 $ 287 $ 37 $ 644
Other income (loss) (a) 2 - - - - -
Inter-segment revenues 234 - - 62 21 1
---------------------------------------------------------------------------------------------------------------------------
Total 359 73 63 349 58 645
Earnings from equity investments 1 - - 9 2 1
Earnings (loss) from continuing operations 20 (5) 6 113 12 1
Earnings from discontinued operations - - - - - -
---------------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 20 (5) 6 113 12 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 $ 74 $ 33 $ - $ - $ - $ 27 $ 1,361
Other income (loss) (a) - 2 - 5 - (2) 7
Inter-segment revenues 4 - - - - (322) -
---------------------------------------------------------------------------------------------------------------------------
Total 78 35 - 5 - (297) 1,368
Earnings from equity investments 18 5 - - - 15 51
Earnings (loss) from continuing operations 23 14 (19) (28) (13) (11) 113
Earnings from discontinued operations - - - - - 1 1
---------------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 23 14 (19) (28) (13) (10) 114
---------------------------------------------------------------------------------------------------------------------------
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.
-31-
Segment Information Exploration & Production Trade
For the Six Months North America International
ended June 30, 2003
Millions of dollars U.S. Lower 48 Alaska Canada Far East Other
---------------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 302 $128 $ 95 $ 608 $141 $1,658
Other income (loss) (a) 49 - - - - (1)
Inter-segment revenues 672 - 79 163 - 1
---------------------------------------------------------------------------------------------------------------------------
Total 1,023 128 174 771 141 1,658
Earnings from equity investments 9 - - 19 5 1
Earnings (loss) from continuing operations 200 29 32 237 50 (5)
Earnings from discontinued operations - - - - - -
Cumulative effect of accounting change (b) 11 (43) 4 13 - -
---------------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 211 (14) 36 250 50 (5)
---------------------------------------------------------------------------------------------------------------------------
Assets (at June 30, 2003) 3,245 329 1,318 3,018 896 364
---------------------------------------------------------------------------------------------------------------------------
Midstream Geothermal Corporate & Other Total
& Power
Operations Admin Net Interest Environmental
& General Expense & Litigation Other (c)
---------------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 269 $ 63 $ - $ - $ - $ 75 $ 3,339
Other income (loss) (a) 2 2 - 10 - 8 70
Inter-segment revenues 4 - - - - (919) -
---------------------------------------------------------------------------------------------------------------------------
Total 275 65 - 10 - (836) 3,409
Earnings from equity investments 32 5 - - - 25 96
Earnings (loss) from continuing operations 36 19 (45) (59) (45) (63) 386
Earnings from discontinued operations - - - - - 8 8
Cumulative effect of accounting change (b) (2) - - - - (66) (83)
---------------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 34 19 (45) (59) (45) (121) 311
---------------------------------------------------------------------------------------------------------------------------
Assets (at June 30, 2003) 596 535 - - - 1,235 11,536
---------------------------------------------------------------------------------------------------------------------------
(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.
-32-
Segment Information Exploration & Production Trade
For the Six Months North America International
ended June 30, 2002
Millions of dollars U.S. Lower 48 Alaska Canada Far East Other
---------------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 237 $124 $103 $ 517 $ 60 $1,100
Other income (loss) (a) 5 - - - - -
Inter-segment revenues 400 - - 114 41 1
---------------------------------------------------------------------------------------------------------------------------
Total 642 124 103 631 101 1,101
Earnings from equity investments - - - 17 4 -
Earnings (loss) from continuing operations 24 (11) (3) 203 24 2
Earnings from discontinued operations - - - - - -
---------------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 24 (11) (3) 203 24 2
---------------------------------------------------------------------------------------------------------------------------
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 $ 136 $ 61 $ - $ - $ - $ 58 $ 2,396
Other income (loss) (a) 1 4 - 8 - 3 21
Inter-segment revenues 6 - - - - (562) -
---------------------------------------------------------------------------------------------------------------------------
Total 143 65 - 8 - (501) 2,417
Earnings from equity investments 37 2 - - - 28 88
Earnings (loss) from continuing operations 42 20 (43) (65) (36) (22) 135
Earnings from discontinued operations - - - - - 1 1
---------------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 42 20 (43) (65) (36) (21) 136
---------------------------------------------------------------------------------------------------------------------------
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.
18. Subsequent Event
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. At June 30,
2003, minority interests on the Company's balance sheet included the $252
million related to Spirit LP. 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.
-33-
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 Six Months
Ended June 30, Ended June 30,
------------------------------------------
Millions of dollars 2003 2002 2003 2002
--------------------------------------------------------------------------------
Earnings from continuing operations $ 169 $ 113 $ 386 $ 135
Earnings from discontinued operations 8 1 8 1
Cumulative effects of accounting changes - - (83) -
--------------------------------------------------------------------------------
Net earnings $ 177 $ 114 $ 311 $ 136
================================================================================
Continuing Operations
Second Quarter Results: Earnings from continuing operations increased by $56
million in the second quarter of 2003 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 $90
million. The Company's worldwide average realized natural gas price, including a
loss of 7 cents per Mcf from hedging activities, was $3.53 per Mcf for the
current quarter. This was an increase of 66 cents per Mcf, or 23 percent, from
the $2.87 per Mcf realized during the same period a year ago. In the current
quarter, the Company's worldwide average realized liquids price was $25.36 per
Bbl, which was an increase of $2.11 per Bbl, or 9 percent, from the same period
a year ago. The Company's hedging program lowered the average realized liquids
price by 4 cents per Bbl in the current quarter while the second quarter of the
prior year included a loss of one cent per Bbl from hedging activities. In the
current quarter, International production contributed approximately $29 million
in higher earnings. The largest contributor to the higher International
production was Thailand, where oil-equivalent production was up 10 percent from
last year's second quarter. Crude oil and condensate production increased 29
percent, primarily because of de-bottlenecking production from the Yala-Plamuk
oil project and higher condensate production from the Pailin Phase 2 project.
Quarterly natural gas production increased 5 percent from last year due to
increased demand tied to higher electric power needs and reduced volumes from
other suppliers. The Company functions as the "swing producer" in Thailand,
providing above-contract minimum volumes when required to meet Thailand's needs.
The Company has routinely produced more than its contract minimums. Higher
production from Azerbaijan and Bangladesh also contributed to increases in
International production. In addition, the Company recorded a $20 million
after-tax gain from the sale of its interest in Matador Petroleum Corporation
("Matador"), which was accounted for as an equity investment.
These positive variance factors were partially offset by lower North America
production and higher amortization of exploratory leasehold costs, which reduced
net earnings by approximately $25 million and $16 million, respectively, in the
current quarter compared with the same period a year ago. North America liquids
production averaged 84,000 Bbl/d in the current quarter, down from 96,000 Bbl/d
in the same period a year ago, while natural gas production averaged 805 MMcf/d
in the current quarter, down from 935 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. The higher amortization of exploratory leasehold costs
is primarily a result of the anticipated relinquishment of about 45 deepwater
Gulf of Mexico blocks before their expiration dates.
-34-
Higher pension related expenses also reduced net earnings by approximately $11
million in the current quarter compared to the same period a year ago. In
addition, the Company recorded a $17 million after-tax ($27 million pre-tax)
restructuring charge aimed at strengthening the Company's Lower 48 businesses,
realigning its corporate staff and shared resource groups, and improving its
balance sheet. In the second quarter of 2002, the Company recorded a $12 million
after-tax ($19 million pre-tax) restructuring charge in its Gulf Region business
unit.
The second quarters of 2003 and 2002 both included after-tax gains of $2 million
and $4 million, respectively, in mark-to-market accruals and realized
gains/losses for non-hedge commodity derivatives recorded by the Company's
Northrock Resources Ltd. ("Northrock") subsidiary. After-tax environmental and
litigation expenses were $29 million in the current quarter of 2003, compared
with $15 million in the same period a year ago.
Six Months Results: Earnings from continuing operations were $386 million in the
first six months of 2003 compared to $135 million for the same period a year
ago. The increase was primarily due to higher worldwide natural gas and liquids
prices. Higher worldwide commodity prices increased net earnings by
approximately $310 million. The Company's worldwide average realized natural gas
price, including a loss of 17 cents per Mcf from hedging activities, was $3.71
per Mcf in the first six months of 2003. This was an increase of $1.03 per Mcf,
or 38 percent, from the $2.68 per Mcf, including a benefit of 6 cents per Mcf
from hedging activities, realized during the first six months of 2002. In the
first six months of 2003, the Company's worldwide average realized liquids price
was $27.54 per Bbl, which was an increase of $6.41 per Bbl, or 30 percent, from
the same period a year ago. The Company's hedging program lowered the average
realized liquids price by 26 cents per Bbl in the first six months of 2003 while
the first six months of 2002 included a gain of 2 cents per Bbl from hedging
activities. International production also contributed approximately $37 million
in higher earnings, primarily from the higher Thailand production. The first six
months of 2003 included the $20 million after-tax gain on the sale of the equity
interest in Matador and an after-tax gain of $4 million in mark-to-market
accruals and realized gains/losses for non-hedge commodity derivatives recorded
by the Company's Northrock subsidiary. The results in the first six months of
2002 included a $12 million after-tax impairment in Alaska.
These 2003 positive variance factors were partially offset by lower North
America production, higher dry hole costs in the Gulf of Mexico, higher pension
related expenses and the higher amortization of exploratory leasehold costs,
which reduced net earnings by approximately $30 million, $24 million, $19
million and $16 million, respectively, in the first six months of 2003 compared
with the same period a year ago. North America liquids production averaged
85,000 Bbl/d in the first six months of 2003, down from 98,000 Bbl/d a year ago,
while natural gas production averaged 833 MMcf/d down from 934 MMcf/d for the
six 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. After-tax
environmental and litigation expenses were $46 million in the first six months
of 2003, compared with $38 million in the same period a year ago. The first six
months of 2003 included the company-wide $17 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 second quarter of 2003 were $1.62
billion compared with $1.37 billion for the same period a year ago. In the first
six months of 2003, total revenues from continuing operations were $3.41 billion
compared with $2.42 billion for the same period a year ago. The increases, in
both the quarter and six months amounts, primarily reflected higher crude oil
and natural gas prices.
-35-
OPERATING HIGHLIGHTS For the Three Months For the Six Months
Ended June 30, Ended June 30,
-----------------------------------------
2003 2002 2003 2002
--------------------------------------------------------------------------------
North America Net Daily Production
Liquids (thousand barrels)
U.S. Lower 48 (a) (b) 44 54 46 55
Alaska 23 25 22 25
Canada 17 17 17 18
--------------------------------------------------------------------------------
Total liquids 84 96 85 98
Natural gas - dry basis (million cubic feet)
U.S. Lower 48 (a) (b) 652 766 678 754
Alaska 67 77 64 89
Canada 86 92 91 91
--------------------------------------------------------------------------------
Total natural gas 805 935 833 934
North America Average Prices (excluding hedging activities) (c)
Liquids (per barrel)
U. S. Lower 48 $ 26.02 $ 23.49 $ 28.11 $ 20.95
Alaska $ 27.46 $ 24.74 $ 31.34 $ 21.99
Canada $ 23.52 $ 21.92 $ 26.05 $ 19.15
Average $ 25.93 $ 23.56 $ 28.48 $ 20.89
Natural gas (per mcf)
U. S. Lower 48 $ 5.01 $ 3.12 $ 5.66 $ 2.68
Alaska $ 1.20 $ 1.57 $ 1.20 $ 1.57
Canada $ 5.13 $ 3.03 $ 5.40 $ 2.54
Average $ 4.69 $ 2.98 $ 5.27 $ 2.55
--------------------------------------------------------------------------------
North America Average Prices (including hedging activities) (c)
Liquids (per barrel)
U. S. Lower 48 $ 25.84 $ 23.48 $ 27.22 $ 21.01
Alaska $ 27.46 $ 24.74 $ 31.34 $ 21.99
Canada $ 23.52 $ 21.92 $ 26.05 $ 19.15
Average $ 25.84 $ 23.56 $ 27.99 $ 20.92
Natural gas (per mcf)
U. S. Lower 48 $ 4.86 $ 3.12 $ 5.23 $ 2.80
Alaska $ 1.20 $ 1.57 $ 1.20 $ 1.57
Canada $ 4.79 $ 2.97 $ 5.07 $ 2.62
Average $ 4.53 $ 2.97 $ 4.89 $ 2.66
--------------------------------------------------------------------------------
(a) Includes proportional interests in production of equity investees.
(b) Includes minority interests of :
Liquids 1 9 1 9
Natural gas 11 98 10 98
Barrels oil equivalent 3 25 2 25
(c) Excludes gains/losses on derivative positions not accounted for as hedges
and ineffective portions of hedges.
-36-
OPERATING HIGHLIGHTS (CONTINUED) For the Three Months For the Six Months
Ended June 30, Ended June 30,
-----------------------------------------
2003 2002 2003 2002
--------------------------------------------------------------------------------
International Net Daily Production (d)
Liquids (thousand barrels)
Far East 59 54 57 53
Other (a) 20 20 21 20
--------------------------------------------------------------------------------
Total liquids 79 74 78 73
Natural gas - dry basis (million cubic feet)
Far East 911 883 890 852
Other (a) 89 79 100 78
--------------------------------------------------------------------------------
Total natural gas 1,000 962 990 930
International Average Prices (d)(e)
Liquids (per barrel)
Far East $ 24.78 $ 22.50 $ 27.06 $ 20.95
Other $ 25.16 $ 23.91 $ 27.11 $ 23.03
Average $ 24.90 $ 22.84 $ 27.07 $ 21.43
Natural gas (per mcf)
Far East $ 2.74 $ 2.78 $ 2.75 $ 2.70
Other $ 2.89 $ 2.79 $ 2.86 $ 2.64
Average $ 2.76 $ 2.78 $ 2.76 $ 2.69
--------------------------------------------------------------------------------
Worldwide Net Daily Production (a) (b) (d)
Liquids (thousand barrels) 163 170 163 171
Natural gas-dry basis (million cubic feet) 1,805 1,897 1,823 1,864
Barrels oil equivalent (thousands) 463 486 467 482
Worldwide Average Prices (excluding hedging activities) (c)
Liquids (per barrel) $ 25.40 $ 23.26 $ 27.80 $ 21.11
Natural gas (per mcf) $ 3.60 $ 2.87 $ 3.88 $ 2.62
Worldwide Average Prices (including hedging activities) (c) (e)
Liquids (per barrel) $ 25.36 $ 23.25 $ 27.54 $ 21.13
Natural gas (per mcf) $ 3.53 $ 2.87 $ 3.71 $ 2.68
--------------------------------------------------------------------------------
(a) Includes proportional interests in production of equity investees.
(b) Includes minority interests of :
Liquids 1 9 1 9
Natural gas 11 98 10 98
Barrels oil equivalent 3 25 2 25
(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 the second quarter of 2003 included a $27
million pre-tax charge as a result of the restructuring program announced in
June that is aimed at strengthening the Company's Lower 48 businesses,
realigning its corporate staff and shared resource groups, and improving its
balance sheet. The higher administrative and general expense category also
reflected higher pension-related expenses.
Exploration expense was higher in the second quarter of 2003 primarily from
higher amortization of leasehold costs of $26 million pre-tax that were a result
of the Company's anticipated relinquishment of about 45 deepwater Gulf of Mexico
blocks before their expiration dates. This reflects the decision to focus the
Company's deepwater Gulf of Mexico land position on those OCS blocks that have
the best potential.
-37-
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, 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.
Second Quarter Results: Earnings from continuing operations were $111 million in
the second quarter of 2003 compared to $21 million for the same period a year
ago, which was an increase of $90 million. The increase was primarily due to
higher natural gas and liquids prices, which increased net earnings by
approximately $82 million. The Company also recorded a $20 million after-tax
gain from the sale of its interest in Matador. These positive factors were
partially offset by lower natural gas and liquids production, and higher
amortization of exploratory leasehold costs, which reduced after-tax earnings by
approximately $25 million and $16 million, respectively. The second quarters of
2003 and 2002 included after-tax gains of $2 million and $4 million,
respectively, in mark-to-market accruals and realized gains/losses for non-hedge
commodity derivatives recorded by the Company's Northrock subsidiary. The second
quarter 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.
Six Months Results: Earnings from continuing operations were $261 million in the
first six months of 2003 compared to $10 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 $263 million. In addition, the Company
recorded the $20 million gain from the sale of its interest in Matador. These
positive factors were partially offset by lower natural gas and liquids
production, higher dry hole costs, and higher exploratory land provisions, which
reduced after-tax earnings by approximately $30 million, $23 million and $18
million, respectively. The six months period of 2002 included the $12 million
after-tax impairment in the Alaska business unit and the $12 million after-tax
restructuring charge in the Gulf Region business unit. The first six months of
2003 included the after-tax gain of $4 million in mark-to-market accruals and
realized gains/losses for non-hedge commodity derivatives recorded by the
Company's Northrock subsidiary.
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.
Second Quarter Results: Earnings from continuing operations totaled $145 million
in the current quarter compared to $125 million in the same period a year ago,
which was an increase of $20 million. The increase was primarily due to $26
million in higher liquids production and $8 million in higher liquids prices.
Higher International liquids production was mainly from Thailand due to
de-bottlenecking production from the Yala-Plamuk oil project and higher
condensate production from the Pailin Phase 2 project. These positive factors
were partially offset by approximately $7 million in higher DD&A expense
(including asset retirement obligation accretion).
-38-
Six Months Results: Earnings from continuing operations totaled $287 million in
the first six months of 2003 compared to $227 million in the same period a year
ago, which was an increase of $60 million. The increase was primarily due to $40
million in higher liquids prices and $37 million in higher liquids and natural
gas production. These positive factors were partially offset by approximately
$23 million in higher DD&A expense (including asset retirement obligation
accretion). 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 aforementioned 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.
Second Quarter Results: Earnings from continuing operations totaled $4 million
in the current quarter compared to $1 million in the same period a year ago. The
higher results reflect gains from crude oil and natural gas trading activities,
which were positively impacted by volatile commodity prices.
Sales and operating revenues from the Trade business segment were $738 million
in the current quarter compared to $644 million in the same quarter a year ago,
which was an increase of $94 million. These revenues represented approximately
47 percent and 48 percent of the Company's total sales and operating revenues
for the second quarters of 2003 and 2002, respectively. Natural gas revenues, as
a result of higher prices, constituted the majority of the increase.
Six Months Results: The results for the first six months were a loss of $5
million compared to earnings of $2 million in the same period a year ago. The
decrease was primarily due to lower results related to domestic natural gas and
crude oil marketing activities, which were negatively impacted by volatile
commodity prices.
Sales and operating revenues were $1.66 billion in the first six months of 2003
compared to $1.1 billion in the same period a year ago, which was an increase
of $558 million. These revenues represented approximately 50 percent and 46
percent of the Company's total sales and operating revenues for the first six
months of 2003 and 2002, respectively. In the first six months of 2003, natural
gas revenues increased by approximately $360 million and crude oil revenues
increased by approximately $200 million, primarily due to higher commodity
prices, as compared to the same period a year ago.
-39-
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.
Second Quarter Results: Earnings from continuing operations totaled $18 million
in the current quarter compared to $23 million in the same period a year ago.
The decrease was due primarily to $4 million in lower results from the pipelines
business, which resulted from lower throughput volumes and the divestiture from
certain of the Company's pipeline interests.
Six Months Results: Earnings from continuing operations totaled $36 million in
the first six months of 2003 compared to $42 million in the same period a year
ago. The decrease was due primarily to $6 million in lower results from the
pipelines business and $3 million from expenses related to the
Baku-Tbilisi-Ceyhan pipeline project. These negative factors were partially
offset by improved results in the gas storage business.
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.
Second Quarter Results: Earnings from continuing operations totaled $7 million
in the current quarter compared to $14 million in the same period a year ago.
The lower current period results were primarily impacted by lost steam sales and
higher operating expenses necessitated by repairs to facilities damaged by major
flooding and landslides at the Company's Salak geothermal project area in
Indonesia.
Six Months Results: Earnings from continuing operations totaled $19 million in
the first six months of 2003 compared to $20 million in the same period a year
ago. The period results included the losses attributable to the flooding and
landslides discussed above, which were partially offset by 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.
Second Quarter Results: The results for the current quarter were a loss of $116
million compared to a loss of $71 million in the same period a year ago. The
current quarter included the $17 million restructuring charge (see note 4 to the
consolidated financial statements in Item 1 of this report). After-tax expenses
for environmental and litigation matters for the current quarter were $28
million compared to $13 million after-tax for the same period a year ago. In
addition, the current quarter reflected approximately $13 million after-tax in
higher pension related expenses.
Six Months Results: The results for the first six months were a loss of $212
million compared to a loss of $166 million in the same period a year ago. The
first six months of 2003 included the $17 million restructuring charge and
higher pension related expenses of $17 million. After-tax expenses for
environmental and litigation matters for the six months of 2003 were $45 million
compared to $36 million after-tax for the same period a year ago. Net interest
expense was $6 million lower in the first six months of 2003 compared to the
same period a year ago, primarily due to higher capitalized interest on
development projects.
-40-
FINANCIAL CONDITION
Cash flows from operating activities, including working capital and other
changes, were $1.09 billion for the six months ended June 30, 2003, compared
with $626 million 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 of
certain domestic trade receivables sold under the Company's accounts receivable
securitization program.
Pre-tax proceeds from asset sales were $191 million for the six months ended
June 30, 2003. The Company received $80 million from the sale of its equity
interest 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 $105 million in proceeds. Pre-tax proceeds from asset sales
including those classified as discontinued operations were $47 million for the
six months ended June 30, 2002. These proceeds included $27 million from the
sale of oil and gas producing properties in the U.S. by the Company's Pure
subsidiary, while the remaining $20 million were from various other oil and gas
asset sales and other miscellaneous properties.
Capital expenditures were $917 million for the first six months of 2003 compared
with $830 million in the same period a year ago. Capital expenditures for 2003
are currently forecast at approximately $1.73 billion, essentially unchanged
from 2002. Capital expenditures reflect higher 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 in the Gulf of
Mexico. In the first six months of 2003, the Company's capital expenditures
included approximately $405 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 June 30,
2003, was $3.0 billion, basically unchanged from the end of 2002. During the
first six 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 and repaid $20 million of 6.20% Industrial Development Revenue
Bonds. These decreases were partially offset by $79 million drawn under the
Overseas Private Investment Corporation ("OPIC") Financing Agreement for the
first phase of the West Seno project in Indonesia (see note 11 for further
detail on the Company's long-term debt). Cash and cash equivalents on hand
totaled $363 million at June 30, 2003, up from $168 million at the end of 2002.
The Company's long-term debt ratings remain stable.
The Company has two credit facilities in place: a $400 million 364-day credit
agreement and a $600 million 5-year credit agreement, maturing October 2006. 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 June 30, 2003, the borrowing under the
credit facility translated to $218 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
paid off the $252 million limited partner interest in Spirit Energy 76
Development, L.P. in July. This financing would have been reclassified from
minority interests to debt in the third quarter pursuant to Financial Accounting
Standards Board Interpretation 46 ("Consolidation of Variable Interest
Entities"). Further, the Company has substantial borrowing capacity to enable it
to meet unanticipated cash requirements.
-41-
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 June 30, 2003, the Company did not have an
outstanding balance under its accounts receivable securitization program, which
was at the $108 million level at year-end 2002. The Company also had in place a
universal shelf registration statement as of June 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.
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 June 30, 2003, the Company's
remediation reserve totaled $267 million, of which $121 million was included in
current liabilities. During the six months period ended June 30, 2003, cash
payments of $30 million were applied against the reserve and $52 million in
provisions were 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 $205 million.
The Company's total environmental reserve and possible additional liability
amounts are grouped into the following four categories.
At June 30, 2003
----------------------------
Possible
Additional
Millions of dollars Reserve Costs
--------------------------------------------------------------------------------
Superfund and similar sites $ 17 $ 15
Active Company facilities 31 25
Company facilities sold with retained liabilities
and former Company-operated sites 98 80
Inactive or closed Company facilities 121 85
--------------------------------------------------------------------------------
Total $ 267 $ 205
================================================================================
Also see notes 13 and 14 to the consolidated financial statements in Item 1 of
this report for additional information on environmental related matters.
During the first six months of 2003, the Company recorded provisions of $40
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.
-42-
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 six 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.
During the first six months of 2003, provisions of $9 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. 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.
During the first six months of 2003, estimated possible additional costs in
excess of amounts included in the reserves for remediation obligations decreased
by $40 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
six 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.
-43-
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 foward-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
470,000 to 480,000 BOE per day. This production forecast includes the associated
production loss of approximately 5,000 BOE per day from divestitures that the
Company has completed so far this year. This estimate also reflects the sale of
the Company's interest in Matador and a one-month delay in the start-up of the
West Seno field in Indonesia. The Company has additional property divestitures
pending or planned that if sold are expected to reduce production by 25,000 to
30,000 BOE per day. 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 in West Seno production, and production and
exploration performance in the Gulf of Mexico. For the remainder of 2003, the
Company has hedged 49.5 million MMBtus of Lower 48 natural gas production and
2.8 million Bbl of Lower 48 crude oil, together representing approximately 40
percent of expected Lower 48 BOE production. The Company has fixed price sales
for 26 milion MMBtu of natural gas at $5.94 per MMBtu and 1.2 million Bbl of
crude oil at $30.08. In addition, the Company has hedged 23 million MMBtu of
natural gas with pricing collars between $4.65 and $3.79 per MMBtu and 1.6
million Bbl of crude oil with collars between $31.85 and $27.38 per Bbl. Based
on current prices, the Company's net earnings for the full-year are expected to
change 14 cents per share for each $1 change in the Company's average worldwide
realized price for crude oil and 7 cents per share for every 10-cent change in
its average realized North America natural gas price, excluding the effect of
hedging activities. The Company forecasts pre-tax dry hole costs of $155 million
to $185 million and that pre-tax pension-related expenses will increase over
2002 by approximately $65 million to $70 million.
Exploration and Production - North America
U.S. Lower 48
The Company continues its deep shelf program in the Gulf of Mexico. Production
at the Harvest deep shelf discovery on West Cameron Block 44 commenced in late
June, adding to the two other deep shelf producing fields. The Company is
currently drilling a prospect at High Island Block 37, which is adjacent to the
Jalapeno discovery in High Island 36 made in 2002. The Company expects to drill
as many as 10 more wells in the remaining months of 2003.
-44-
In the Gulf of Mexico deepwater, the Company completed a successful appraisal
well at the Champlain discovery located on Atwater Valley Block 63. The Company
participated in the appraisal well, which earned it a 30 percent interest in the
discovery by paying for 50 percent of the well costs. The Company and its
co-venturers will be working on development options and are aiming to sanction
the project by year-end. The Champlain prospect is important to the Company
because of its proximity to the Mirage discovery, located on Mississippi Canyon
Block 941, where it has a 25 percent non-operating working interest.
The Company plans to continue funding the development of the Mad Dog discovery
in which the Company has a 15.6 percent non-operating working interest. The
Company anticipates first production in late 2004 or early 2005, with gross
expected production of 75 MBbl/d of liquids and 35 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 in 2003.
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.
The Company is currently drilling a well on its St. Malo prospect in the Walker
Ridge area, a deep Eocene test. The Company received a 32 percent working
interest in the well by paying 27.5 percent of the well cost. The Company is
solidifying the drilling schedule for the remainder of the year and expects to
drill another two wells in the Gulf of Mexico deepwater in 2003.
The Company announced that it has initiated a divestiture program that will
involve approximately 100 fields in the Gulf of Mexico shelf and onshore (see
note 10 to the consolidated financial statements in Item 1 of this report).
On July 15, 2003, the Company's wholly owned affiliate, Chicago Carbon Company
("Chicago"), filed with the SEC, an amended Schedule 13D with respect to
Chicago's 14.71% interest in Tom Brown, Inc. ("Tom Brown"). The filing was made
to reflect that Chicago had given notice to Tom Brown, of its request that the
5,800,000 shares of common stock it holds in Tom Brown be registered under the
shelf registration statement that Tom Brown had filed with the SEC. In the event
that Tom Brown's shelf registration statement is amended to include all of the
shares owned by Chicago and that statement is declared effective by the SEC,
then Chicago would be in a position to sell its Tom Brown shares subject to the
usual and customary shelf registration statement procedures and the requirements
of the contractual registration rights with Tom Brown.
Alaska
The Ninilchik Unit development in the South Kenai Peninsula is progressing.
First production from the Ninilchik Unit is also expected in the fourth quarter
of 2003, with that early production going to the Kenai Gas Storage Facility for
delivery to customers beginning in the first quarter of 2004. The Company has a
40 percent non-operating interest in the unit.
-45-
Exploration and Production - International
Far East
Thailand: Demand for natural gas from the Company's fields has been strong as a
result of the ongoing reduced production from adjacent fields operated by other
companies. The Company expects higher average liquids production, with the
full-year effect of crude oil production from its Yala field. The Company has a
71 percent working interest in the Yala field (62 percent net of royalty). The
Company's plans are geared towards exploring for additional oil and gas
resources in the Gulf of Thailand and supporting the efforts of PTT Exploration
and Production PLC 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's new production from the deepwater West Seno oil and gas field came
on line in early August 2003. Gross daily production from the first phase of
development is expected to reach about 35 MBOE to 40 MBOE by the end of 2003,
increasing to a peak production level of approximately 60 MBbl/d of oil and 150
MMcf/d of natural gas (gross) in late 2005 with the second phase of development.
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 $300 million for the first phase, and the other loan is $50 million
for the second phase. The loan associated with the second phase is still subject
to a final construction contract being obtained.
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 well was not planned to penetrate the deep reservoir that
was encountered in the Gehem-1 well. 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. Extending the Ranggas oil and gas
accumulations to the south is an important and positive appraisal step for the
field. While the Company is still planning to have the Ranggas development
project ready for government approval by early next year, the Gehem-1 results
have implications for appraising the deeper oil potential at Ranggas and
optimizing the development. The Company plans to move the Ranggas project along
while assessing the deep potential and options for co-development with Gehem.
Unocal Rapak is operator of the Rapak PSC area and holds an 80-percent working
interest.
The Company will be drilling another deep 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 Company holds a 50 percent working interest in the
well.
China: The Company has worked with China National Offshore Oil Corporation,
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 is continuing its negotiations and is still expecting
to sign PSCs in 2003 to explore and develop natural gas resources. The Company's
working interest is expected to be 20 percent.
-46-
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 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 expected project financing from international lending institutions like the
IFC and EBRD and from several export credit agencies, should help to mitigate
the political risk.
Bangladesh: Domestic natural gas sales in the country have expanded and the
Company 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. 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 July 31, 2003, the Company's business unit
in Bangladesh had a gross receivable balance of approximately $23 million
relating to invoices billed for natural gas and condensate sales to Petrobangla.
Approximately $20 million of the outstanding balance represented past due
amounts and accrued interest for invoices covering March through June 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.
The government of Bangladesh has also approved the development plan of the
Moulavi Bazar natural gas field in northeast Bangladesh. The Company is awaiting
the required approval from Petrobangla for the gas sales and purchase contracts.
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. While the Company
continues to evaluate the effect of these actions by the United States
Government, it appears that they 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 15 percent of the
project completed. 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 the
pipeline 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 expects to sign a bridge financing agreement in the near
future 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.
The Kenai Kachemak Pipeline in Alaska, currently under construction, will
transport natural gas from Ninilchik to Kenai, where it will tie into the
existing gas grid serving south central Alaska. The Company expects the 32-mile
pipeline to be in operation in the fourth quarter of 2003.
-47-
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, the
Power Sector Assets and Liabilities Corporation and the Philippine Department of
Energy signed a compromise settlement agreement covering the definitive terms of
settlement in March 2003. The parties are now in 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 in the third
quarter of 2003, and the Company expects to record a gain on the transaction
(see note 10 to the consolidated financial statements in Item 1 of this report).
FUTURE ACCOUNTING CHANGES
FASB Interpretation No. 46: Effective January 1, 2003, the Company adopted FASB
Interpretation No. 46, "Consolidation of Variable Interest Entities." (see note
2 to the consolidated financial statements in Item 1 of this report). The
effective date for the consolidation of entities existing prior to February 1,
2003 is July 1, 2003. The Company expects the adoption of the recognition (i.e.,
consolidation) requirements of the Interpretation to increase its consolidated
long-term debt by approximately $78 million in the third quarter of 2003. This
covers third-party debt of DSPL (see note 12 to the consolidated financial
statements in Item 1 of this report). An additional $242 million related to a
partnership interest in which the Company had a minority interest liability
would have been required to be consolidated under this Interpretation had it not
been paid in July (see note 18 to the consolidated financial statements in Item
1 of this report).
SFAS No. 149: In April 2003, the FASB issued 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. SFAS No. 149 is effective for contracts entered into or
modified after June 30, 2003. The Company does not expect the adoption of SFAS
No. 149 to have a significant impact on its financial position or results of
operations.
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.
-48-
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 June 30, 2003. Assuming a ten percent decrease in the
Company's weighted average borrowing costs at June 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 $95 million at June 30, 2003.
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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.
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 June 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 swaps and
forward contracts. Assuming an adverse change of ten percent in foreign exchange
rates at June 30, 2003, the potential decrease in fair value of the Company's
foreign currency forward contracts, foreign-currency denominated debt, foreign
currency swaps and foreign currency forward contracts of its subsidiaries, would
have been approximately $28 million at June 30, 2003.
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 $17
million at June 30, 2003. The value at risk related to hydrocarbon derivatives
held for non-hedging purposes was approximately $1 million at June 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 June 30, 2003, along with the
fair values of those instruments.
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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) (13,960,000) (9,850,000) - - - $ 8,920
Average price, per MMBtu $ 5.92 $ 6.06
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Swap Positions
Pay fixed price
Volume (MMBtu) 8,368,500 14,726,500 7,893,000 7,218,000 14,459,000 $ 75,395
Average swap price, per MMBtu $ 4.46 $ 4.02 $ 2.59 $ 2.42 $ 2.50
Receive fixed price
Volume (MMBtu) 8,240,000 11,830,000 - - - $ 7,323
Average swap price, per MMBtu $ 6.12 $ 6.14
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Basis Swap Positions
Volume (MMBtu) 19,650,000 - - - - $ 3,045
Average price received, per MMBtu $ 5.20
Average price paid, per MMBtu $ 4.61
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Collar Positions
Volume (MMBtu) 23,811,000 268,500 - - - $ (24,837)
Average ceiling price, per MMBtu $ 4.64 $ 5.45
Average floor price, per MMBtu $ 3.79 $ 2.82
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Option (OTC)
Put Volume (MMBtu) (12,300,000) - - - - $ 1,364
Average Put Price $ 3.25
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Future position
Volume (Bbls) (760,000) - - - - $ (1,559)
Average price, per Bbl $ 29.54
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Option
Put Volume (Bbls) - - - - - $ (101)
Average price, per Bbl $ -
Call Volume (Bbls) - - - - - $ 97
Average price, per Bbl $ -
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Option (OTC)
Put Volume (Bbls) (1,200,000) (720,000) - - - $ 977
Average price, per Bbl $ 24.00 $ 20.00
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Collar Positions
Volume (Bbls) 1,277,500 810,000 - - - $ (1,264)
Average ceiling price, per Bbl $ 32.25 $ 28.16
Average floor price, per Bbl $ 27.43 $ 23.41
====================================================================================================================================
(a) Positions reflect long (short) volumes.
(b) Net claims against counterparties with non-investment grade credit ratings are immaterial.
(c) Includes $6,127 thousand in assumed liabilities which were capitalized as acquisition costs.
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Open Hydrocarbon Non-Hedging Derivative Instruments (a)
(Thousands of dollars)
2003 2004 Fair Value
Asset(Liability) (b)
----------------------------------------------------------------------------------------------- --------------- --------------------
Natural Gas Futures Positions
Volume (MMBtu) 8,700,000 - $ (3,920)
Average price, per MMBtu $ 5.73
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Swap Positions
Pay fixed price
Volume (MMBtu) 7,030,000 - $ (2,355)
Average swap price, per MMBtu $ 5.77
Receive fixed price
Volume (MMBtu) 7,894,748 95,438 $( 4,878)
Average swap price, per MMBtu $ 5.61 $ 1.99
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Basis Swap Positions
Volume (MMBtu) - - $ 67
Average price received, per MMBtu $- $ -
Average price paid, per MMBtu $- $ -
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Spread Swap Positions
Volume (MMBtu) 4,429,999 3,630,000 $ 4,218
Average price received, per MMBtu $ 0.70 $ 1.34
Average price paid, per MMBtu $ 0.54 $ 0.36
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Option (Listed)
Call Volume (MMBtu) (29,380,000) - $ 4,027
Average Call price $ 6.42 $ -
Put Volume (MMBtu) 8,150,000 - $ ( 548)
Average Put Price $ 5.27 $ -
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Option (Over the Counter)
Call Volume (MMBtu) (2,236,150) - $ (3,318)
Average Call price $ 3.85 $ -
Put Volume (MMBtu) (4,620,000) (1,820,000) $ 557
Average Put price $ 4.26 $ 4.50
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Spread Option (Over the Counter)
NYMEX / IFERC (c)
Call Volume (MMBtu) ( 810,000) (470,000) $ 100
Average Strike price $ 1.14 $2.00
Put Volume (MMBtu) (3,000,000) - $ 60
Average Strike price $ 0.25 $ -
------------------------------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Future position
Volume (Bbls) - - $ 65
Average price, per Bbl $-
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Option
Put Volume (Bbls) - - $ (370)
Average price, per Bbl $ -
Call Volumes (Bbls) 200,000 - $ 184
Average price, per Bbl $ 32.50
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Swap Positions
Pay fixed price
Volume (Bbls) 2,732,500 - $ 1,768
Average swap price, per Bbl $ 27.85
Receive fixed price
Volume (Bbls) 2,650,000 - $ (2,394)
Average swap price, per Bbl $ 27.57
------------------------------------------------------------------------------------------------------------------------------------
(a) Positions reflect long (short) volumes.
(b) Includes $3,932 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).
-52-
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 second 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 attest to, 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, 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 period ended
March 31, 2003. There is incorporated by reference: the information regarding
the environmental remediation reserve and possible additional remediation costs
in notes 13 and 14 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 14 to the consolidated financial statements.
Information with respect to recent developments in certain previously reported
proceedings is set forth below:
1. In the federal cases (the Doe and Roe cases) alleging the Company's
liability in connection with the construction of the natural gas pipeline
from the Yadana field across Myanmar to the Thailand border, described in
Paragraph 2 of Item 3 of the 2002 Form 10-K, a rehearing took place in
June 2003 before an eleven-judge "en banc" panel of the U.S. Court of
Appeals for the Ninth Circuit of the appellate court decision remanding
the cases for further proceedings in the District Court. A decision is not
expected for several months.
In the California Superior Court cases, the court has bifurcated the
trial. Phase I will address whether the correct defendants are before the
court. If Unocal is unsuccessful in Phase I, then Phase II will address
liability and damages. Phase I is currently scheduled for September 2003
and Phase II for December 2003.
The Company believes that the outcomes of the federal and state cases are
not likely to have a material adverse effect on the Company's financial
condition or liquidity or, based on management's current assessment of the
cases, the Company's results of operations.
-54-
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
The 2003 Annual Meeting of Stockholders of Unocal was held on May 19, 2003. The
following actions were taken by the stockholders at the Annual Meeting, for
which proxies were solicited pursuant to Regulation 14 under the Securities
Exchange Act of 1934, as amended:
1. The four nominees proposed by the board of directors were elected as
directors by the following votes for three-year terms expiring at the
2006 Annual Meeting of Stockholders, or until their successors are duly
elected and qualified:
Name Votes For Votes Withheld
John W. Amerman 218,336,231 8,195,535
John W. Creighton, Jr. 218,441,184 8,093,582
Ferrell P. McClean 218,714,080 7,820,686
Kevin W. Sharer 219,524,450 7,010,316
2. A proposal to ratify the appointment of PricewaterhouseCoopers LLP as
Unocal's independent accountants for 2003 was passed by a vote of
217,480,891 for versus 7,556,964 against and 1,492,890 abstentions.
There were 4,022 broker non-votes.
3. A stockholder proposal to urge the Board of Directors to take the
necessary steps to amend the bylaws to require that an independent
director who has not served as chief executive officer of the Company
to serve as chairman of the Board of Directors failed to pass, with a
vote of 20,361,699 for versus 175,106,931 against and 2,281,969
abstentions. There were 28,784,168 broker non-votes.
4. A stockholder proposal to request the Board of Directors to take the
needed steps to hire an investment banking firm to sell the Company
failed to pass, with a vote of 7,827,942 for versus 187,072,700 against
and 2,849,956 abstentions. There were 28,784,169 broker non-votes.
-55-
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits: The Exhibit Index on page 57 of this report lists the
exhibits that are filed as part of this report.
(b) Reports on Form 8-K:
Filed during the second quarter of 2003:
(1) Current Report on Form 8-K, dated April 1, 2003, and filed
April 2, 2003, for the purpose of reporting, under Item 5
and Item 7, an amendment to Unocal's Rights Agreement.
(2) Current Report on Form 8-K, dated April 24, 2003, and filed
April 28, 2003, for the purpose of reporting, under Item 5,
the Company's first quarter 2003 earnings and related
information and the Company's 2003 outlook.
(3) Current Report on Form 8-K, dated and filed June 5, 2003,
for the purpose of reporting, under Item 5, the Company's
intent to sell assets in the U.S. Gulf of Mexico and other
business related news.
(4) Current Report on Form 8-K, dated and filed June 27, 2003,
for the purpose of reporting, under Item 5 and Item 7, the
Company's acquisition of the outstanding limited partner
interest in a consolidated limited partnership.
Filed during the third quarter of 2003 to the date hereof:
(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.
-56-
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
UNOCAL CORPORATION
(Registrant)
Dated: August 11, 2003 By: /s/ JOE D. CECIL
------------------------------
Joe D. Cecil
Vice President and Comptroller
(Duly Authorized Officer and
Principal Accounting Officer)
-57-
EXHIBIT INDEX
10 Employment Agreement, effective as of March 12, 2003, by and between Unocal
and Thomas E. Fisher.
12.1 Statement regarding computation of ratio of earnings to fixed charges of
Unocal Corporation for the six months ended June 30, 2003 and 2002.
12.2 Statement regarding computation of ratio of earnings to fixed charges of
Union Oil Company of California for the six months ended June 30, 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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