text:
[X]  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended   March 31, 2005
[ ]  TRANSITION  REPORT  PURSUANT TO SECTION 13 OR 15(D) OF THE  SECURITIES
For the transition period from               to
--------------  -------------------
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)
Indicate  by check  mark  whether  the  registrant:  (1) has filed  all  reports
required to be filed by Section 13 or 15(d) of the  Securities  Exchange  Act of
1934  during  the  preceding  12 months  (or for such  shorter  period  that the
registrant was required to file such reports),  and (2) has been subject to such
filing requirements for the past 90 days.        Yes     X        No
-------          -------
Indicate by check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Exchange Act).  Yes     X        No
Number of shares of common stock, $1.00 par value, outstanding as of
April 29, 2005:  271,781,763
GLOSSARY                                                                      i
FORWARD-LOOKING STATEMENTS                                                   iii
PART I.  FINANCIAL INFORMATION
Item 1.     Financial Statements.
Consolidated Earnings                                     1
Consolidated Balance Sheets                               2
Consolidated Cash Flows                                   3
Notes to Consolidated Financial Statements                4
Item 2.     Management's Discussion and Analysis of Financial
Condition and Results of Operations.                          27
Item 3.     Quantitative and Qualitative Disclosures About Market Risk.   39
Item 4.     Controls and Procedures.                                      42
PART II.  OTHER INFORMATION
Item 1.     Legal Proceedings.                                            43
Item 2.     Unregistered Sales of Equity Securities and Use of Proceeds.  43
Item 6.     Exhibits.                                                     44
SIGNATURE                                                                    45
Below are definitions of certain common industry terms that may be used in this
Form 10-Q:
M            Thousand                    Bbl          Barrels
MM           Million                     Cf/d         Cubic feet per day
B            Billion                     Cfe/d        Cubic feet of gas
T            Trillion                                 equivalent per day
Btu          British thermal units
CF           Cubic feet                  DD&A         Depreciation, depletion
and amortization
BOE          Barrels of oil equivalent   NGLs         Natural gas liquids
Liquids      Crude oil, condensate
and NGLs
Bbl/d        Barrels per day
o    API gravity is a measurement of the gravity (density) of crude oil and
other liquid hydrocarbons by a system recommended by the American Petroleum
Institute ("API"). The measuring scale is calibrated in terms of "API
degrees." The higher the API gravity, the lighter the crude oil.
o    Bilateral institution refers to a country specific institution that lends
funds primarily to promote the export of goods from that country. Examples
of bilateral institutions are Ex-Im (U.S.), Hermes (Germany), SACE (Italy),
COFACE (France), and JBIC (Japan).
o    BOE is a term used to quantify crude oil and natural gas amounts using a
standard measurement. Natural gas volumes are converted to barrels of oil
equivalent on the basis of 6,000 cubic feet of natural gas equals one
barrel of oil equivalent.
o    British Thermal Units ("Btu") is a standardized unit of measure for energy,
equivalent to the amount of heat required to raise the temperature of one
pound of water one degree Fahrenheit. Ten thousand MMBtu (million Btu) is
the standard volume for exchange traded natural gas derivative contracts,
the approximate heat content of ten thousand Mcf (thousand cubic feet) of
natural gas.
o    Delineation or appraisal well is a well drilled in an unproven area
adjacent to a discovery well to define the boundaries of the reservoir.
o    Development well is a well drilled within the proved area of an oil or gas
reservoir to a depth of a stratigraphic horizon known to be productive.
o    Dry hole is a well incapable of producing hydrocarbons in sufficient
commercial quantities to justify future capital expenditures for completion
and additional infrastructure.
o    Economic interest method pursuant to production sharing contracts is a
method by which our share of the cost recovery revenue and the profit
revenue is divided by market oil and gas prices and represents the volume
to which we are entitled. The lower the commodity price, the higher the
volume entitlement, and vice versa.
o    Exploratory well is a well drilled to find and produce oil or gas reserves
that is not a development well.
o    Farm-in or farm-out is an agreement whereby the owner of a working interest
in an oil and gas lease assigns the working interest or a portion thereof
to another party who agrees to pay a portion of past or future costs. The
interest received by an assignee is a "farm-in," while the interest
transferred by the assignor is a "farm-out."
o    Field is an area consisting of a single reservoir or multiple reservoirs
all grouped on or related to the same individual geological structural
feature or stratigraphic condition.
o    Floating Production, Storage and Offloading ("FPSO") technology refers to
the use of a vessel that is stationed above or near an offshore field.
Produced fluids are brought by flowlines to the vessel where they are
separated, or treated, or stored and then offloaded to another vessel or
pipeline for transportation.
o    Gross acres or gross wells are the total acres or wells in which we have a
working interest.
o    Hydrocarbons are organic compounds of hydrogen and carbon atoms that form
the basis of all petroleum products.
o    Lifting is the amount of liquids each working-interest partner takes
physically. The liftings may be more or less than actual entitlements based
on royalties, working interest percentages, and a number of other factors.
o    Liquefied Natural Gas ("LNG") is a gas, mainly methane, which has been
liquefied in a refrigeration and pressurization process to facilitate
storage and transportation.
o    Liquefied Petroleum Gas ("LPG") is a mixture of butane, propane and other
light hydrocarbons. At normal temperature it is a gas, but when cooled or
subjected to pressure it can be stored and transported as a liquid.
o    Multilateral institution refers to an institution with shareholders from
multiple countries that lends money for specific development reasons.
Examples of multilateral institutions are International Finance Corporation
("IFC"), European Bank for Reconstruction and Development ("EBRD"), and
Asian Development Bank ("ADB").
o    Natural Gas Liquids ("NGLs") are primarily ethane, propane, butane and
natural gasolines, which can be extracted from wet natural gas and become
liquid under various combinations of increasing pressure and lower
o    Net acreage and net oil and gas wells are obtained by multiplying gross
acreage and gross oil and gas wells by our working interest percentage in
the properties.
o    Net pay is the amount of oil or gas saturated rock capable of producing oil
or gas.
o    Net working interest is a working interest after deducting royalties and
other economic interests payable to third parties. Our net working interest
may vary over time due to changes in commodity prices, costs and other
factors.
o    OPEC is the abbreviation for Organization of Petroleum Exporting Countries.
o    Producible well is a well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of
production exceed production expenses and taxes.
o    Production Sharing Contract ("PSC") is a contractual agreement between us
and a host government whereby we, acting as contractor, bear exploration,
development and production costs in return for an agreed upon share of the
proceeds from the sale of production.
o    Prospective acreage is lease acreage on which wells have not been drilled
or completed to a point that would permit the production of commercial
quantities of crude 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 crude
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. In some contracts,
the purchaser has the right in following years to take product that had
been paid for but not taken.
o    Trend or Play is an area or region of concentrated activity with a group of
related fields and/or prospects.
o    Working Interest ("WI") is the percentage of ownership we have in a joint
venture, partnership, consortium, project or acreage. Our working interest
does not necessarily equal our share of revenues or production. See "Net
working interest" definition above.
o    West Texas Intermediate ("WTI") crude oil is a light, sweet crude oil (high
API gravity, low sulfur) used as the benchmark for U.S. crude oil refining
and trading. WTI is deliverable at Cushing, Oklahoma to fill New York
Mercantile Exchange ("NYMEX") futures contracts for light, sweet crude oil.
For the purpose of this report, the terms "Unocal," "Union Oil," "we,"
"our," "its" and the "Company" refer to Unocal Corporation ("Unocal") and its
consolidated subsidiaries, including Union Oil Company of California ("Union
Oil"), unless the context otherwise provides.
This cautionary note is provided pursuant to the safe harbor provisions
of the Private Securities Litigation Reform Act of 1995 and Section 27A of the
Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.
Forward-looking statements are included in this report and may be included in
other public filings, press releases, our website and oral and written
presentations by management. Statements other than historical facts are
forward-looking and may be identified by words such as "expects," "anticipates,"
"intends," "plans," "believes," "estimates," "forecasts," "could," "will" and
words of similar meaning. Examples of these types of statements include those
o the anticipated consummation of our merger with ChevronTexaco,
o assessments of hydrocarbon formations and potential resources,
o exploration, development and other plans for future operations,
o production rates, timing and costs and sales volumes and prices,
o revenues, earnings, cash flows, liabilities, capital expenditures and other
financial measures,
o anticipated liquidity,
o the amount and timing of environmental and other contingent liabilities, and
o other statements regarding future events, conditions or outcomes.
Although these statements are based upon our current expectations and
beliefs, they are subject to known and unknown risks and uncertainties that
could cause actual results and outcomes to differ materially from those
described in, or implied by, the forward-looking statements. In that event, our
business, financial condition, results of operations or liquidity could be
materially adversely affected and investors in our securities could lose part or
all of their investments. These risks and uncertainties include, for example:
o whether the pending merger with ChevronTexaco will be completed and the
effects on us in the event that it is not completed,
o volatility in commodity prices,
o our ability to find or acquire commercially productive reservoirs and to
develop and produce deepwater and other projects in a timely and
cost-effective manner,
o the accuracy of our estimates and judgments regarding hydrocarbon resources
and formations and reservoir performance,
o operational risks inherent in the exploration, development and production of
oil and gas,
o the impact of environmental laws, permitting and licensing requirements and
other regulations,
o international and domestic political and economic factors, and
o other factors discussed in our Risk Factors section in Part II, Item 7 of our
2004 Annual Report on Form 10-K.
Copies of our SEC filings are available by calling us at (800) 252-2233
or from the SEC by calling (800) SEC-0330. The reports are also available on our
web site, www.unocal.com. We undertake no obligation to update the
forward-looking statements in this report or in other documents, our website or
oral statements to reflect future events or circumstances. All such statements
are expressly qualified by this cautionary statement.
ITEM 1.  FINANCIAL STATEMENTS
CONSOLIDATED EARNINGS (UNAUDITED)                             UNOCAL CORPORATION
For the Three Months
Ended March 31,
Millions of dollars except per share amounts              2005             2004
Sales and operating revenues (a) (see note 3)          $ 2,157          $ 1,821
Interest, dividends and miscellaneous income                 9               11
Gain on sales of assets (see note 4)                        20               44
Total revenues                                     2,186            1,876
Crude oil, natural gas and product purchases (a)           754              744
Operating expense                                          307              281
Administrative and general expense                          78               63
Depreciation, depletion and amortization                   276              232
Impairments                                                  -                5
Dry hole costs                                              20               25
Exploration expense (see note 3)                            38               50
Interest expense (see note 3)                               33               41
Property and other operating taxes                          21               20
Total costs and other deductions                   1,527            1,461
Earnings from equity investments                            39               37
Earnings from continuing operations before
income taxes and minority interests                   698              452
Income taxes                                               247              180
Minority interests                                           2                5
Earnings from continuing operations                        449              267
Earnings from discontinued operations (b)                    5                2
Net earnings                                     $   454          $   269
Basic earnings per share of common stock (c)
Continuing operations                            $  1.66          $  1.02
Discontinued operations                             0.02             0.01
Net earnings                                     $  1.68          $  1.03
Diluted earnings per share of common stock (d)
Cash dividends declared per share of common stock      $  0.20          $  0.20
(a)  Includes crude oil buy/sell transactions
settled in cash of:                            $   163          $   252
(b)  Net of tax (benefit)                              $     4          $     1
(c)  Basic weighted average shares outstanding
(in thousands)                                 270,445          261,974
(d)  Diluted weighted average shares outstanding
See Notes to the Consolidated Financial Statements.
CONSOLIDATED BALANCE SHEETS                                   UNOCAL CORPORATION
At March 31,    At December 31,
Millions of dollars                                  2005 (a)              2004
Cash and cash equivalents (see note 9)             $  1,683           $  1,160
Accounts and notes receivable - net (see note 3)      1,448              1,423
Inventories (see note 3)                                142                220
Deferred income taxes                                    75                 88
Other current assets                                     49                 39
Total current assets                             3,397              2,930
Investments and long-term
receivables - net (see note 3)                          717                777
Properties - net (see note 3)                          8,916              8,819
Goodwill                                                 135                136
Deferred income taxes                                    311                272
Other assets                                             214                167
Total assets                                  $ 13,690           $ 13,101
Accounts payable                                   $  1,219           $  1,298
Taxes payable                                           535                410
Dividends payable                                        54                 53
Interest payable                                         48                 38
Current portion of environmental
liabilities (see note 15)                              114                109
Current portion of long-term debt and
capital leases (see note 13)                           428                491
Other current liabilities                               257                182
Total current liabilities                        2,655              2,581
Long-term debt and capital leases (see note 13)        2,302              2,571
Accrued abandonment, restoration and
environmental liabilities (see note 15)                 900                897
Other deferred credits and liabilities                 1,078                969
Minority interests                                        28                 27
Commitments and contingencies - (see note 16)
Common stock ($1 par value, shares authorized:
750,000,000 (b))                                        288                280
Capital in excess of par value                         1,651              1,304
Unearned portion of restricted stock issued              (39)               (23)
Retained earnings                                      4,854              4,453
Accumulated other comprehensive income                  (239)              (160)
Notes receivable - key employees                          (3)                (3)
Treasury stock - at cost  (c)                           (634)              (634)
Total stockholders' equity                       5,878              5,217
Total liabilities and stockholders' equity    $ 13,690           $ 13,101
(a)  Unaudited
(b)  Number of shares outstanding (in thousands)     271,655            263,190
(c)  Number of shares (in thousands)                  16,538             16,538
CONSOLIDATED CASH FLOWS (UNAUDITED)                           UNOCAL CORPORATION
Millions of dollars                                       2005             2004
Net earnings                                           $   454            $ 269
Adjustments to reconcile net earnings to
Depreciation, depletion and amortization             276              232
Impairments                                            -                5
Dry hole costs                                        20               25
Amortization of exploratory leasehold costs           14               16
Deferred income taxes                                 43               28
Gain on sales of assets                              (20)             (44)
Gain on disposal of discontinued operations           (4)               -
Pension expense net of contributions                  24               23
Other                                                 (4)             (13)
Working capital and other changes related to operations
Accounts and notes receivable                         (25)              72
Inventories                                            78               31
Accounts payable                                      (79)              29
Taxes payable                                         125              106
Other                                                   6              (29)
Net cash provided by operating activities      908              750
Capital expenditures (includes dry hole costs)         (419)            (360)
Proceeds from sales of assets                            96               72
Return of capital from affiliate company                  -               52
Net cash used in investing activities         (323)            (236)
Long-term borrowings                                      -               40
Reduction of long-term debt and
capital lease obligations                            (102)            (197)
Minority interests                                       (2)               -
Repurchases of common stock                               -              (20)
Proceeds from issuance of common stock                   95               51
Dividends paid on common stock                          (53)             (52)
Loans to key employees                                    -               20
Net cash used in financing activities             (62)            (158)
Net increase in cash and cash equivalents                  523              356
Cash and cash equivalents at beginning of year           1,160              404
Cash and cash equivalents at end of period             $ 1,683            $ 760
Supplemental disclosure of cash flow information:
Interest (net of amount capitalized)               $  21            $  33
Income taxes (net of refunds)                      $  83            $   6
1.   General
The consolidated financial statements included in this report are unaudited and,
in the opinion of our management, include all adjustments necessary for a fair
presentation of our financial position and results of operations. All
adjustments are of a normal recurring nature.
Certain notes and other information have been condensed or omitted from these
interim financial statements in accordance with the Securities and Exchange
Commission ("SEC") disclosure requirements for Form 10-Q. Therefore, these
interim consolidated financial statements should be read in conjunction with the
consolidated financial statements and the related notes filed with the SEC in
our 2004 Annual Report on Form 10-K ("2004 10-K").
Our consolidated financial statements include the accounts of subsidiaries in
which a controlling interest is held and variable interest entities where Unocal
is the primary beneficiary. Undivided interests in oil and gas joint ventures
are consolidated on a proportionate basis.
Investments in entities without a controlling interest are accounted for by the
equity method or cost basis. Under the equity method, our investments are stated
at cost plus the equity in undistributed earnings and losses after acquisition.
Income taxes estimated to be payable when earnings are distributed are included
in deferred income taxes. Other securities and investments excluding marketable
securities are generally carried at cost. Under the cost method, the investments
are recorded at cost, and we recognize as income dividends received that are
distributed from net accumulated earnings of the investee since the date of
acquisition.
We follow the successful efforts method of accounting for our oil and gas
Results for the three months ended March 31, 2005, are not necessarily
indicative of future financial results.
The financial statements of the prior periods have been reclassified to conform
to the 2005 presentation.
2.   Accounting Changes and New Accounting Pronouncements
Emerging Issues Task Force ("EITF") Issue 04-9 and Financial Accounting
Standards Board ("FASB") Staff Position ("FSP") FAS 19-1: Statement of Financial
Accounting Standards ("SFAS") No. 19, "Financial Accounting and Reporting by Oil
and Gas Producing Companies" requires the cost of drilling an exploratory well
to be capitalized pending determination of whether the well has found proved
reserves. If this determination cannot be made at the conclusion of drilling,
SFAS No. 19 sets out additional requirements for continuing to carry the cost of
the well as an asset. These requirements include firm plans for further drilling
and a one-year time limitation on continued capitalization in certain instances.
The EITF in their discussions of this issue noted that as a result of the
increasing complexity of oil and gas projects due to drilling in remote and
deepwater offshore locations, companies increasingly require more than one year
to complete all of the activities that permit recognition of proved reserves.
Furthermore, because of new technologies, additional exploratory wells may no
longer be required before a project can commence. EITF Issue 04-9, "Accounting
for Suspended Well Costs," sought to determine whether SFAS No. 19 should be
clarified to recognize the industry changes that have taken place in the past
quarter century. This issue was discussed by the EITF and it was determined that
a formal amendment to SFAS No. 19 would be required if the FASB concurs with
broadening the requirements for continued capitalization of exploratory well
costs. In April 2005, the FASB issued FSP FAS 19-1, which we adopted effective
January 1, 2005. This FSP amends SFAS No. 19 to allow continued capitalization
when (a) the well has found a sufficient quantity of reserves to justify
proceeding with the project plan and (b) the enterprise is making sufficient
progress assessing the reserves and the economic and operating viability of the
project which may include more than one exploratory well if the reserves are
intended to be extracted in a single integrated operation. The FSP also requires
increased disclosures, which are presented in note 11. Adoption of this rule did
not impact our consolidated earnings in the first quarter of 2005. If this FSP
had been applied to 2004, it would not have had a material effect on our
earnings for that year.
American Jobs Creation Act: The American Jobs Creation Act of 2004 (the "Act")
was signed into law by the U.S. President on October 22, 2004. The Act contains
numerous changes to U.S. tax law, both temporary and permanent in nature,
including a potential tax deduction with respect to certain qualified domestic
manufacturing activities, which will be phased in from 2005 through 2010. Under
the guidance in FSP FAS 109-1, "Application of FASB Statement No. 109,
"Accounting for Income Taxes," to the Tax Deduction on Qualified Production
Activities Provided by the American Jobs Creation Act of 2004," the deduction
will be reported in the period in which the deduction is claimed on our tax
return. Based on current earnings levels, we estimate the increase in net
earnings generated by this deduction will be in the range of zero to $5 million
in both calendar years 2005 and 2006 and in the range of zero to $20 million per
year by the end of the phase-in period in 2010.
The Act creates a temporary incentive for U.S. corporations to repatriate
accumulated income earned abroad by providing an 85 percent dividends received
deduction for certain dividends from controlled foreign corporations. Because we
incur a foreign tax rate in excess of the 35 percent U.S. federal income tax
rate, we do not pay incremental federal income tax on our foreign earnings due
to excess foreign tax credits. Therefore, we do not anticipate repatriating
higher amounts of foreign earnings under the Act since any such repatriations
would not reduce federal income taxes. In addition, this Act includes changes in
the carryback and carryforward utilization periods for foreign tax credits.
SFAS No. 151: In 2004, the FASB issued SFAS No. 151, "Inventory Costs - an
amendment of ARB No. 43, Chapter 4," which is effective for inventory costs
incurred after December 31, 2005. This statement requires that items such as
idle facility expense, excessive spoilage, double freight, and rehandling costs
be recognized as current-period charges regardless of whether they meet the
criterion of "so abnormal" as provided in Chapter 4 of ARB No. 43. In addition,
this statement requires that fixed production overhead allocated to inventory be
based on the normal capacity of the production facilities. Adoption of this
pronouncement is not expected to have a significant impact on either our
earnings or consolidated balance sheet.
SFAS No. 123 (revised 2004): In 2004, the FASB issued SFAS No. 123 (revised
2004) "Share-Based Payment," an amendment of FASB Statement Nos. 123 and 95,
which is effective January 1, 2006. This pronouncement requires the fair value
method to account for share-based awards and potentially increases the number of
grants considered liability awards. In addition to more disclosures and a change
in reporting the cash flows of certain stock option excess realized income tax
benefits, it also requires liability awards to be reported at fair value rather
than intrinsic value. Equity awards will continue to be recorded at grant-date
fair value and recognized over the vesting period. Liability awards will be
reported at fair value until settlement or expiration. Because we commenced in
2003 to prospectively expense new stock option grants, this standard is not
expected to have a material impact on either our earnings or consolidated
balance sheet.
SFAS No. 153: In 2004, the FASB issued SFAS No. 153, "Exchanges of Nonmonetary
Assets, an amendment of APB Opinion No.29," which is effective July 1, 2005.
With certain exceptions, this requires exchanges of nonmonetary assets to be
recorded at fair value. Previously, these transactions were generally recorded
at book value. This pronouncement results in reporting in earnings, gains and
losses on exchanges of nonmonetary assets. Adoption of this rule is not expected
to have a material impact on either our earnings or consolidated balance sheet.
EITF Issue No. 04-13: In 2004, the EITF initiated a review under Issue No.
04-13, "Accounting for Purchases and Sales of Inventory with the Same
Counterparty," to determine if they should be reported on a gross basis or a net
basis. For many years, we have used a type of transaction commonly called a
buy/sell, which generally consists of the purchase and sale of crude oil from
the same counterparty. In a typical buy/sell transaction, Company A enters into
a contract to sell a particular grade of crude oil at a specified location to
Company B on a future date, and simultaneously agrees to buy from Company B a
particular grade of crude oil at a different location at the same or another
specified date.
The characteristics of buy/sell transactions include gross invoicing reflecting
the quality and location differences of the crude oil, physical delivery
requirements and separate payment terms. Nonperformance by one party does not
relieve the other party's obligation to perform under the contract except for
events of force majeure. The risks and rewards of ownership are evidenced by
title transfer, assumption of environmental risk, transportation scheduling and
counterparty credit risk. Because of these characteristics, we, as well as many
of our industry peers, report the sale of the barrels as gross revenues and the
purchase of the barrels as gross purchases in accordance with EITF Issue No.
99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent." These
characteristics also provide evidence that these transactions are monetary in
nature and thus outside the scope of APB Opinion No. 29.
We understand that some registrants in our industry may report buy/sell
transactions using a net rather than a gross presentation. The EITF is reviewing
these transactions to determine if more specific guidance is needed for
determining whether a net rather than a gross presentation in consolidated
earnings is appropriate. While a net presentation of this issue would reduce
both our revenues and our purchases, our net earnings would not be affected.
FASB Interpretation No. 47: In March 2005, the FASB issued FASB Interpretation
No. 47, "Accounting for Conditional Asset Retirement Obligations, an
interpretation of FASB Statement No. 143," which is effective no later than
December 31, 2005. This pronouncement clarifies that the term "conditional asset
retirement obligation" as used in FASB Statement 143, Accounting for Asset
Retirement Obligations, refers to a legal obligation to perform an asset
retirement activity in which the timing and (or) method of settlement are
conditional on a future event that may or may not be within the control of the
entity. The obligation to perform an asset retirement activity is unconditional
even though uncertainty exists about the timing and (or) method of settlement.
Accordingly, an entity is required to recognize a liability for the fair value
of a conditional asset retirement obligation if the fair value of the liability
can be reasonably estimated. When sufficient information exists, uncertainty
about the timing and (or) method of settlement should be factored into the
measurement of the liability. This interpretation is not expected to have a
material impact on either our earnings or consolidated balance sheet.
3.   Other Financial Information
o    Revenues - Sales and operating revenues from marketing activities were
$895 million in the first quarter of 2005, compared with $833 million in
the same period a year ago.  During the first quarters of 2005 and 2004, 21
percent and 28 percent, respectively, of sales and operating revenues were
attributable to the resale of crude oil, natural gas and natural gas
liquids purchased from outside parties by our Midstream and Marketing
segment.  These percentages in both years included crude oil buy/sell
transactions.  Crude oil buy/sell amounts were primarily lower due to a
significant decrease of volumes associated with these transactions, which
was partially offset by higher crude oil prices for the periods shown
(see crude oil buy/sell discussions in Item 8 of our 2004 10-K in the
consolidated financial statements under notes 1 and 2).  These marketing
activities allowed us to better manage commodity-related risk by
effectively transferring commodities from production locations to industry
marketing centers with higher volumes of commercial activity and greater
market liquidity.
o    Exploration expense - Our exploration expense on the consolidated earnings
statement consisted of the following:
Millions of dollars                                          2005          2004
Exploration operations                                       $ 13          $ 17
Geological and geophysical                                      9            15
Amortization of exploratory leasehold costs                    14            16
Leasehold rentals                                               2             2
Exploration expense                                     $ 38          $ 50
o    Capitalized interest - During the first quarters of 2005 and 2004,
capitalized interest totaled $15 million and $16 million, respectively. The
slight decrease in 2005 was primarily due to lower capitalized interest
from the Mad Dog project in the Gulf of Mexico, which began production in
January 2005. This decrease was mostly offset by higher capitalized
interest from the ongoing Azeri-Chirag-Gunashli ("ACG") project in
Azerbaijan.
o    Accounts and notes receivable - The allowance for doubtful accounts and
notes receivable was $5 million at March 31, 2005, unchanged from December
o    Inventories - In the first quarter of 2005, inventories decreased by $78
million from year-end 2004 reflecting seasonal natural gas withdrawals in
our Canadian natural gas storage business.
o    Investments and long-term receivables - The allowances for investments and
long-term receivable were $14 million and $32 million at March 31, 2005 and
December 31, 2004, respectively.
o    Properties - Accumulated depreciation, depletion and amortization was
$12,813 million and $12,597 million at March 31, 2005 and December 31,
2004, respectively.
4.   Dispositions Of Assets
Certain of our first quarter 2005 asset sales are discussed below:
In February 2005, we sold our Unocal Bharat Limited ("Unocal Bharat")
subsidiary, which held our 26 percent equity interest in Hindustan Oil
Exploration Company ("HOEC") and received $25 million in net cash proceeds. HOEC
is India's only publicly traded oil and gas exploration and production company
outside the state controlled sector. We recorded an after-tax gain of $22
million in the first quarter of 2005.
In March 2005, our Molycorp subsidiary sold down its equity investment in
Companhia Brasileira de Metalurgia e Mineracao, a niobium operation in Brazil,
from 40 percent to 35 percent for $27 million in net cash proceeds. We recorded
an after-tax gain of $2 million.
5.   Income Taxes
Income taxes on earnings from continuing operations for the first quarter of
2005 totaled $247 million compared with $180 million for the same period a year
ago. The effective income tax rate for the first quarter of 2005 was 35 percent
as compared to 40 percent for the first quarter of 2004. The overall lower
effective tax rate is due primarily to tax related benefits accrued related to
the sale of Unocal Bharat in the first quarter of 2005.
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 quarters ended March 31, 2005 and 2004:
Earnings     Shares     Per Share
Millions of dollars except per share amounts (Numerator) (Denominator)   Amount
Three months ended March 31, 2005
Earnings from continuing operations         $ 449        270
Basic EPS                                                       $ 1.66
Effect of dilutive securities
Options and common stock equivalents                   3
Diluted EPS                             $ 449        273        $ 1.64
267        265        $ 1.01
Interest on convertible debentures
payable to trust (after-tax)             7         12
Options outstanding to purchase 1.4 million of common stock were not included in
the computation of diluted EPS for the three months ended March 31, 2004, as the
exercise prices were greater than the average market price of the common shares
during the period. The computation of diluted EPS for the three months ended
March 31, 2005 included all outstanding common stock options.
7.   Comprehensive Income
Unocal's comprehensive income is detailed in the following table:
Millions of dollars                                            2005        2004
Net earnings                                                  $ 454       $ 269
Change in unrealized gain (loss) on hedging instruments (a)     (38)        (27)
Reclassification adjustment for settled hedging contracts (b)   (22)          3
Unrealized foreign currency translation adjustments              (7)         (9)
Minimum pension liability adjustment (c)                        (12)          -
Total comprehensive income                                    $ 375       $ 236
(a) Net of tax effect of:                                       (22)        (16)
(b) Net of tax effect of:                                       (13)          2
(c) Net of tax effect of:                                        (7)          -
8.   Stock-Based Compensation
We began using the fair value recognition provisions of SFAS No. 123,
"Accounting for Stock-Based Compensation," for 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
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:
Millions of dollars except per share amounts                2005           2004
As reported                                            $ 454          $ 269
Add: Stock-based employee compensation expense
included in reported net earnings,
net of related tax effects
and minority interests                                 9              5
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                       (10)            (7)
Pro forma net earnings                                    $ 453          $ 267
Net earnings per share:
Basic - as reported                                   $ 1.68         $ 1.03
Basic - pro forma                                     $ 1.68         $ 1.02
Diluted - as reported                                 $ 1.66         $ 1.00
Diluted - pro forma                                   $ 1.66         $ 0.99
9.   Cash and Cash Equivalents
At March 31, 2005, our cash and cash equivalents had increased by $523 million
from year-end 2004, reflecting the effect of stronger commodity prices during
the quarter.
At March 31,         At December 31,
Millions of dollars                                 2005                   2004
Cash                                               $ 490                  $ 243
Time deposits                                        286                    258
Marketable securities                                907                    659
Cash and cash equivalents                   $ 1,683                $ 1,160
At March 31, 2005, marketable securities totaled $907 million reflecting our
short-term investments primarily in high-grade commercial paper and money market
funds. The money market funds invest in U.S. Treasury and other U.S. government
agency obligations, floating rate and variable rate demand notes of U.S. and
foreign corporations, commercial paper, certificates of deposit and time
deposits, asset backed securities and repurchase agreements. The funds are rated
"Aaa" by Moody's Investors Service, Inc. and/or "AAAm" by Standard & Poor's
Ratings Services. Our commercial paper investments are rated in the highest
category by Moody's Investor Services, Inc. (P1) and Standard & Poor's Ratings
Services (A1). All short-term investments are highly liquid and are part of our
cash management portfolio with original maturities of three months or less.
10.  Assets Held for Sale
At March 31, 2005, we were in the process of completing the sale of our needle
coke business, which we agreed to sell for $25 million in cash plus net working
capital. At March 31, 2005, the business had current assets of $20 million, net
properties of $7 million and current liabilities of $5 million. The sale closed
on April 29, 2005, and we expect to record an after-tax gain of approximately
$11 million in the second quarter of 2005. We have classified the needle coke
business as a discontinued operation and have reflected the results of the
business as such for the first quarter of 2005 and the corresponding prior
period. The needle coke business generated revenues of $41 million and after-tax
earnings of $3 million in the first quarter of 2005, which compared with
revenues of $9 million and an after-tax loss of $1 million in the first quarter
of 2004.
11.  Properties and Capital Leases
As of January 1, 2005, Unocal adopted FASB Staff Position FAS 19-1, "Accounting
for Suspended Well Costs." Upon adoption of the FSP, Unocal evaluated all
existing capitalized exploratory well costs under the provisions of the FSP. As
a result, the Company determined that all these costs meet the criteria for
capitalization under the FSP. The following table reflects the net changes in
capitalized exploratory well costs during the first three months of 2005 and
2004, and does not include amounts that were capitalized and subsequently
expensed or reclassified in the same period. Capitalized exploratory well costs
for the three months ended March 31, 2004, are presented based on the Company's
previous accounting policy.
Beginning balance at January 1                                $ 355       $ 364
Additions to capitalized exploratory well costs
pending the determination of proved reserves                   11          36
Reclassifications to wells, facilities, and equipment
based on the determination of proved reserves                   -           -
Capitalized exploratory well costs charged to expense             -           -
Ending balance at March 31 (a)                                $ 366       $ 400
(a)  Excludes costs of wells where drilling was
in progress at March 31 of:                            $ 18        $ 27
The following table provides an aging of capitalized exploratory well costs
based on the date the drilling was completed and the number of projects for
which exploratory well costs have been capitalized for a period greater than one
year since completion of drilling:
Capitalized exploratory well costs that have been
capitalized for a period of one year or less                $  85       $ 104
capitalized for a period greater than one year                281         296
Balance at March 31                                           $ 366       $ 400
Number of projects that have exploratory well costs that
have been capitalized for a period greater than one year       10          13
The aging of the $281 million March 31, 2005 balance of capitalized exploratory
well costs for suspended wells exceeding one year based on the date drilling was
completed consisted of $35 million in 2004; $49 million in 2003; $56 million in
2002; $77 million in 2001; $44 million in 2000; $16 million in 1999 and $4
million in 1997.
For exploratory well costs that continue to be capitalized for more than one
year after completion of drilling at March 31, 2005, the following provides an
overview of the activities that have been undertaken to evaluate the projects
and potential reserves and the information still required to classify the
associated reserves as proved.
United States ($98 million, 3 projects)
In 2004, we continued our effort to further evaluate and advance the Trident
discovery in the Perdido foldbelt of the deepwater Gulf of Mexico. In 2004, we
drilled an additional successful well at the nearby Tobago prospect, which could
allow for co-development of the two discoveries. We are currently participating
in technical studies with all of the area operators and partners, all of which
already have discoveries in the area, to determine the feasibility of various
co-development options, which will be required before proved reserves can be
booked. Additional exploratory drilling opportunities are currently being
planned in the area and may occur as early as 2005. Any additional exploratory
discoveries in the area are expected to become part of the overall
co-development of our Trident and Tobago discoveries.
A successful appraisal well was drilled in 2004 on the St. Malo discovery that
was made in 2003. An additional appraisal well is firmly planned for 2005. Well
and seismic analysis is ongoing to move this project towards anticipated
sanctioning and proved reserves booking.
An appraisal well is firmly planned for 2005 to further evaluate the 2004 Puma
discovery. This prospect is near the Mad Dog field that began production in
early 2005. Evaluation of the 2005 appraisal well and ongoing seismic analysis
is needed to move this project toward anticipated sanctioning and reserve
booking.
Indonesia ($115 million, 4 projects)
The Gendalo complex project encompasses three deepwater fields in the Kutei
Basin, East Kalimantan, Indonesia. A plan of development covering this project
is currently being prepared and is expected to be submitted to the Government of
Indonesia in 2005.
Gehem field development is planned as part of the Gehem-Ranggas complex, which
is located in the Kutei Basin. Work continued in 2004 with the drilling of a
successful appraisal well. A plan of development is expected to be submitted to
our partner and the Government of Indonesia in 2005. Proved reserves for Gehem
are expected to be booked after all the requisite approvals have been received.
A plan of development is currently expected to be submitted for the Bangka
project, a satellite development to the West Seno producing operation, in 2006.
Conceptual engineering work has started.
Appraisal of the Gula discovery wells continued in 2004 with the drilling of an
appraisal well. Further drilling is currently planned for 2006. Conceptual
engineering, economic analysis and project approval will be necessary before
proved reserves can be booked.
Thailand ($42 million, 1 project)
Efforts to bring the Gulf of Thailand Arthit project to development continued
during 2004 including additional exploratory and delineation drilling to further
evaluate this discovery. Development drilling is planned for late 2005 and
should continue into 2006. The expected completion of a third pipeline to shore
in 2006 by PTT will provide capacity for Arthit's production with expected start
up in the first half of 2007. A gas sales contract was signed in 2004. Proved
reserves are expected to be booked after additional drilling.
Vietnam ($20 million, 1 project)
Additional successful exploratory drilling continued during 2004 to further
appraise the discovery of natural gas reserves offshore of Vietnam. We are also
committed to drilling two additional wells by 2008. We are currently working
with the Vietnamese officials to finalize and obtain government approval for
development plans to supply gas for power generation in the southwest part of
the country. Work is now focused on negotiation and completion of the commercial
agreements to facilitate the development of the integrated project. Assuming
successful completion of the commercial agreements has been achieved, detailed
engineering and development activities would commence. The timing for the
booking of any proved reserves is dependent on finalizing remaining PSC
requirements and concluding all commercial negotiations.
Canada ($6 million, 1 project)
Testing in early 2005 of a Summit Creek exploratory well drilled in 2004 in the
Central MacKenzie Valley area of the Northwest Territories confirmed several
production intervals. A second well drilled in 2005 encountered hydrocarbons at
sub-commercial flow rates and has been suspended. Additional work will be
required to assess the commercial viability of this emerging play.
12.  Postemployment Benefit Plans
We have numerous plans worldwide that provide employees with retirement
benefits. We also have medical plans that provide health care benefits for
eligible employees and many of our retired employees. Most of our plans covering
employees outside of North America are unfunded and resulting liabilities are
extinguished on a "pay as you go" basis.
The components of net periodic benefit cost for our pension and postretirement
medical plans for the three months ended March 31, 2005 and 2004 were:
For the Three Months Ended March 31,
Pension Benefits     Other Benefits
--------------------  --------------
Millions of dollars                            2005      2004      2005    2004
Service cost (net of employee contributions)   $ 10       $ 8       $ 1     $ 1
Interest cost                                    20        20         4       5
Expected return on plan assets                  (20)      (19)        -       -
Amortization of:
Prior service cost                              1         1        (2)      -
Net actuarial losses                           17        16         1       2
Curtailment and settlement losses                 -         -         -       -
Net periodic pension and other benefit costs   $ 28      $ 26       $ 4     $ 8
In the last six months of 2004, we recorded a full year benefit of $11 million
representing the impact of the non-taxable federal subsidy provided for under
the "The Medicare Prescription Drug, Improvement and Modernization Act of 2003."
In keeping with the guidance provided by FSP No. 106-2, the net periodic benefit
cost for our U.S. postretirement medical program for the quarter ended March 31,
2004 has been restated to include the impact of the subsidy.
The assumed weighted-average rates used to determine the net periodic benefit
costs were:
Weighted-average assumptions                 2005      2004      2005      2004
Discount rates                              5.74%     6.00%     5.75%     6.00%
Rates of salary increases                   4.91%     4.91%     4.99%     4.99%
Expected returns on plan assets             8.00%     8.00%       N/A       N/A
In the quarter ended March 31, 2005, no contributions were made to the U.S. Q
ualified Retirement Plan.  Under existing funding regulations, we are not
required to make any cash contributions to our U.S. Qualified Retirement Plan
We previously disclosed in Item 8 of our 2004 10-K in the consolidated financial
statements under note 16 that we expected to contribute approximately $5 million
to our Supplemental Executive Retirement Plan, approximately $17 million to our
foreign pension plans and approximately $25 million to our worldwide
post-retirement medical plans in 2005. As of March 31, 2005, we do not
anticipate that actual contributions for the full year 2005 for these plans will
vary materially from the forecasted levels.
13.  Long Term Debt
Unocal's total consolidated debt, including current maturities, was $2.73
billion at March 31, 2005, compared with $3.06 billion at the end of 2004. In
the first quarter of 2005, we paid Unocal Capital Trust (the "Trust") a
combination of cash and Unocal common stock to retire the $242 million
outstanding balance of the 6-1/4% convertible junior subordinated debentures
(see note 14 for further detail). We also paid $77 million as full payment under
the revolving portion of our Canadian dollar-denominated credit agreement. In
addition, we paid $5 million in medium term notes that matured in the first
quarter of 2005.
14.  Variable Interest Entities
In January 2005, the Trust completed the redemption of its outstanding
convertible preferred securities. Holders converted 4,550,738 preferred
securities into Unocal common stock and redeemed 119,143 preferred securities
for $6 million. Including the 1.25-percent redemption premium and unpaid
distributions, the total cash cost of the redemption was $6 million. In
connection with the redemption program completion, Unocal redeemed $242 million
of its convertible junior subordinated debentures held by the Trust using cash
on hand and by issuing Unocal common stock in January 2005 upon the conversion
by holders of their preferred securities. The Trust utilized the common stock
and cash it received from Unocal to redeem the preferred securities and to
retire the Trust's common securities, which Unocal held as an investment.
15.  Accrued Abandonment, Restoration and Environmental Liabilities
At March 31, 2005, we had accrued $771 million in estimated abandonment and
restoration costs as liabilities. At December 31, 2004, we had accrued $762
million in estimated abandonment and restoration costs. The increase in the
liability account from December 31, 2004 was due to $11 million in accrued
pre-tax accretion expense, $4 million in revisions to existing estimates and $2
million in new abandonment liabilities recorded during the period. These amounts
were partially reduced by abandonment liability settlements totaling $8 million
during the first quarter of 2005.
Our reserve for environmental remediation obligations at March 31, 2005 totaled
$243 million, of which $114 million was included in current liabilities. This
compared with $244 million at December 31, 2004, of which $109 million was
included in current liabilities. The following table shows the environmental
remediation obligations by category:
Millions of dollars                                     2005               2004
Superfund and similar sites                          $  12              $  14
Active Company facilities                               29                 30
Company facilities sold with retained liabilities
and former Company-operated sites                    103                101
Inactive or closed Company facilities                   99                 99
Total                                            $ 243              $ 244
16.  Commitments and Contingencies
Unocal has contingent liabilities for existing or potential claims, lawsuits and
other proceedings, including those involving environmental, tax, guarantees and
other matters, some of which are discussed more specifically below. We accrue
liabilities when it is probable that future costs will be incurred and these
costs can be reasonably estimated. Accruals are based on developments to date,
our estimates of the outcomes of these matters and our experience in contesting,
litigating and settling other matters. As the scope of the liabilities becomes
better defined, there will be changes in the estimates of future costs, which
could have a material effect on our future results of operations, financial
condition or liquidity.
We continue to move forward to address environmental issues for which we are
responsible. In cooperation with regulatory agencies and others, we follow
procedures that we have established to identify and cleanup contamination
associated with past operations. We are subject to loss contingencies pursuant
to federal, state, local and foreign environmental laws and regulations. These
include existing and possible future obligations to investigate the effects of
the release or disposal of certain petroleum, chemical and mineral substances at
various sites; to remediate or restore these sites; to compensate others for
damage to property and natural resources, for remediation and restoration costs
and for personal injuries; and to pay civil penalties and, in some cases,
criminal penalties and punitive damages. These obligations relate to sites owned
by us or owned by others and are associated with past and present operations,
including sites at which we have been identified as a potentially responsible
party ("PRP") under the federal Superfund laws and comparable state laws.
Liabilities are accrued when it is probable that future costs will be incurred
and such costs can be reasonably estimated. However, in many cases,
investigations are not yet at a stage where we are able to determine whether we
are liable or, even if liability is determined to be probable, to quantify the
liability or estimate a range of possible exposure. In such cases, the amounts
of our liabilities are indeterminate due to the potentially large number of
claimants for any given site or exposure, the unknown magnitude of possible
contamination, the imprecise and conflicting engineering evaluations and
estimates of proper clean up methods and costs, the unknown timing and extent of
the corrective actions that may be required, the uncertainty attendant to the
possible award of punitive damages, the recent judicial recognition of new
causes of action, the present state of the law, which often imposes joint and
several and retroactive liabilities on PRPs, the fact that we are usually just
one of a number of companies identified as a PRP, or other reasons.
Assessment and Remediation
As disclosed in note 15, at March 31, 2005, we had accrued $243 million for
estimated future environmental assessment and remediation costs at various sites
where liabilities for such costs are probable and reasonably estimable. The
amount accrued represents our reserve for assessment and remediation obligations
based on currently available facts, existing technology and presently enacted
laws and regulations. The remediation cost estimates, in many cases, are based
on plans recommended to the regulatory agencies for approval and are subject to
future revisions. The ultimate costs to be incurred could exceed the total
amounts reserved. We may also incur additional liabilities in the future at
sites where remediation liabilities are probable but future environmental costs
are not presently reasonably estimable because the sites have not been assessed
or the assessments have not advanced to the stage where costs are reasonably
estimable. At those sites where investigations or feasibility studies have
advanced to the stage of analyzing feasible alternative remedies and/or ranges
of costs, we estimate that we could incur possible additional remediation costs
aggregating approximately $225 million. The amount of such possible additional
costs reflects the aggregate of the high ends of the ranges of costs of feasible
alternatives that we identified for those sites with respect to which
investigation or feasibility studies have advanced to the stage of analyzing
such alternatives. However, such estimated possible additional costs are not an
estimate of the total remediation costs beyond the amounts reserved, because
there are sites where we are not yet in a position to estimate all, or in some
cases any, possible additional costs. Both the amounts reserved and estimates of
possible additional costs will be adjusted, as additional information becomes
available regarding the nature and extent of site contamination, required or
agreed-upon remediation methods and other actions by government agencies and
private parties. Therefore, the amounts reserved and the possible additional
estimated costs may change in the near term, and in some cases could change
During the first quarter of 2005, cash payments of $17 million were applied
against the reserves and $16 million was added to the reserves. Possible
additional remediation costs increased by $10 million during the first quarter
of 2005. The accrued costs and the estimated possible additional costs are shown
below for four categories of sites:
Millions of dollars                                  Reserve    Additional Costs
Superfund and similar sites                            $ 12            $ 15
Active Company facilities                                29              35
and former Company-operated sites                     103              80
Inactive or closed Company facilities                    99              95
Total                                            $243            $225
The time frames over which the amounts included in the reserve may be paid
extend from the near term to several years into the future. The sites included
in the above categories are in various stages of investigation and remediation;
therefore, the related payments against the existing reserve will be made in
future periods. Also, some of the work is dependent upon reaching agreements
with regulatory agencies and/or other third parties on the scope of remediation
work to be performed, who will perform the work, the timing of the work, who
will pay for the work and other factors that may have an impact on the timing of
the payments for amounts included in the reserve. For some sites, the
remediation work will be performed by other parties, such as the current owners
of the sites, and we have a contractual agreement to pay a share of the
remediation costs. For these sites, we generally have less control over the
timing of the work and consequently the timing of the associated payments. Based
on available information, we estimate that the majority of the amounts included
in the reserve will be paid within the next three to five years.
At the sites where we have contractual agreements to share remediation costs
with third parties, the reserve reflects our estimated shares of those costs. In
many of the oil and gas sites, remediation cost sharing is included in joint
venture agreements that were made with third parties during the original
operation of the sites. In many cases where we sold facilities or a business to
a third party, sharing of remediation costs for those sites may be included in
the sales agreement.
Contamination at the sites of the "Superfund and similar sites" category was the
result of the disposal of substances at these sites by one or more PRPs.
Contamination of these sites could be from many sources, of which we may be one.
We have been notified that we are a PRP at the sites included in this category.
At the sites where we have not denied liability, our contribution to the
contamination at these sites was primarily from operations in the other
categories described below. 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 March 31, 2005, we have received notifications from the EPA that we may be a
PRP at 20 sites and may share certain liabilities at these sites. Of the total,
five sites are under investigation and/or litigation, and our potential
liability is not presently determinable; and for two sites, our potential
liability appears to be de minimis. Of the remaining 13 sites, where we have
concluded that liability is probable and to the extent costs can be reasonably
estimated, a reserve of $8 million has been established for future remediation
and settlement costs.
Various state agencies and private parties had identified 24 other similar PRP
sites. Five sites are under investigation and/or litigation, and our potential
liability is not presently determinable; and at three sites, our potential
liability appears to be de minimis. Where we have concluded that liability is
probable and to the extent costs can be reasonably estimated at the remaining 16
sites, a reserve of $4 million has been established for future remediation and
settlement costs.
The sites discussed above exclude 132 sites where our liability has been
settled, or where we have no evidence of liability and there has been no further
indication of liability by government agencies or third parties for at least a
12-month period.
We do not consider the number of sites for which we have been named a PRP as a
relevant measure of liability. Although the liability of a PRP is generally
joint and several, we are usually just one of numerous companies designated as a
PRP. Our ultimate share of the remediation costs at those sites often is not
determinable due to many unknown factors. The solvency of other responsible
parties and disputes regarding responsibilities may also impact our ultimate
The "Active Company facilities" category includes oil and gas fields and mining
operations. The oil and gas sites are primarily contaminated with crude oil, oil
field waste and other petroleum hydrocarbons. Contamination at the active mining
sites was principally the result of the impact of mined material on the
groundwater and/or surface water at these sites. Included in this category are:
o   the Molycorp molybdenum mine in Questa, New Mexico
o   the Molycorp lanthanide facility in Mountain Pass, California
o   Alaska oil and gas properties.
We have a reserve of $29 million for estimated future costs of remedial orders,
corrective actions and other investigation, remediation and monitoring
obligations at certain operating facilities and producing oil and gas fields. We
recorded provisions of $2 million during the first quarter of 2005. During the
first quarter of 2005, we made payments of $3 million for this category of
Company facilities sold with retained liabilities and former Company operated
The "Company facilities sold with retained liabilities and former
Company-operated sites" category includes our former refineries, transportation
and distribution facilities and service stations. The required remediation of
these sites is mainly for petroleum hydrocarbon contamination as the result of
leaking tanks, pipelines or other equipment or impoundments that were used in
these operations. Also included in this category are former oil and gas fields
that we no longer operate. In most cases, these sites are contaminated with
crude oil, oil field waste and other petroleum hydrocarbons. Contamination at
other sites in these categories of sites was the result of former industrial
chemical and polymers manufacturing and distribution facilities and agricultural
chemical retail businesses. Included in this category are:
o   West Coast refining, marketing and transportation sites
o   auto/truckstop facilities in various locations in the U.S.
o   industrial chemical and polymer sites in the South, Midwest and
o   agricultural chemical sites in the West and Midwest.
In each sale, we retained a contractual remediation or indemnification
obligation and are responsible only for certain environmental issues that
resulted from operations prior to the sale. The reserve represents estimated
future costs for remediation work: identified prior to the sale of these sites;
included in negotiated agreements with the buyers of these sites where we
retained certain levels of remediation liabilities; and/or identified in
subsequent claims made by buyers of the properties. Our former operated sites
include service stations, distribution facilities and oil and gas fields that we
previously operated but did not own.
We have an aggregate reserve of $103 million for this group of sites. During the
first quarter of 2005, provisions of $12 million for this category were
recorded. These provisions were primarily for sites that we formerly operated
and were based on new and revised cost estimates that we identified during the
first three months of 2005 for the remediation of approximately 55 service
station, bulk plant and terminal sites and for the assessment and remediation of
oil and gas fields in Central California. Payments of $9 million were made
during the first quarter of 2005 for sites in this category.
The "Inactive or closed Company facilities" category includes former oil and gas
fields and other locations that are no longer operating. In most cases, these
sites are contaminated with crude oil, oil field waste and other petroleum
hydrocarbons. Other sites in this category were contaminated from former
ferromolybdenum production operations. Included in this category are:
o   the Guadalupe oil field on the central California coast
o   the Molycorp Washington facility in Pennsylvania
o   the Beaumont Refinery in Texas.
A reserve of $99 million has been established for these types of facilities.
During the first quarter of 2005, we accrued $2 million related to sites in this
category. Payments of $3 million were made during the first quarter of 2005 for
sites in this category.
We are subject to federal, state and local environmental laws and regulations,
including CERCLA, as amended, RCRA and laws governing low-level radioactive
materials. Under these laws, we are subject to existing and/or possible
obligations to remove or mitigate the environmental effects of the disposal or
release of certain chemical, petroleum and radioactive substances at various
sites. Corrective investigations and actions pursuant to RCRA and other federal,
state and local environmental laws are being performed at our facility in
Beaumont, Texas, a former agricultural chemical facility in Corcoran,
California, Molycorp's facility in Washington, Pennsylvania and other
facilities. In addition, Molycorp is required to decommission its Washington
facility in Pennsylvania pursuant to the terms of its radioactive source
materials license and decommissioning plan.
We also must provide financial assurance for future closure and post-closure
costs of our RCRA-permitted facilities and for decommissioning costs at
Molycorp's Washington Pennsylvania facility under its radioactive source
materials license. Pursuant to a 1998 settlement agreement between us and the
State of California (and the subsequent stipulated judgment entered by the
Superior Court), we must provide financial assurance for anticipated costs of
remediation activities at our former Guadalupe oil field. As previously
discussed, remediation reserves for these sites are included in the "Inactive or
closed Company facilities" category and totaled $84 million at March 31, 2005.
At those sites where investigations or feasibility studies have advanced to the
stage of analyzing alternative remedies and/or ranges of costs, we estimate that
we could incur possible additional remediation costs aggregating approximately
$63 million. Although any possible additional costs for these sites are likely
to be incurred at different times and over a period of many years, we believe
that these obligations could have a material adverse effect on our results of
operations but are not expected to be material to our consolidated financial
We maintain insurance coverage intended to reimburse the cost of damages and
remediation related to environmental contamination resulting from sudden and
accidental incidents under current operations. The purchased coverages contain
specified and varying levels of deductibles and payment limits. Although certain
of our contingent legal
exposures enumerated above are uninsurable either due to insurance policy
limitations, public policy or market conditions, our management believes that
our current insurance program significantly reduces the possibility of an
incident causing us a material adverse financial impact.
Certain Litigation and Claims
Petrobangla Claim: Our subsidiary Unocal Bangladesh Blocks Thirteen and
Fourteen, Ltd. received a letter from Petrobangla claiming, on behalf of itself
and the Bangladesh government, 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 exploration well on the Blocks 13
and 14 PSC area in Northeast Bangladesh. Unocal and OBL believe that the claim
vastly overstates the amount of recoverable natural gas involved in the blowout.
For a further discussion of this claim, refer to the "Petrobangla Claim" section
under note 23 to the consolidated financial statements in Item 8 of our 2004
10-K.
ChevronTexaco Merger Litigation: Unocal and its ten directors are defendants in
two putative class action lawsuits challenging the acquisition of Unocal by
ChevronTexaco. Each complaint was brought by an individual Unocal stockholder in
April 2005 in the Superior Court of California in Los Angeles. The complaints
are substantially similar in alleging that Unocal and its directors breached
their fiduciary duties by (i) failing to maximize stockholder value; (ii)
securing benefits for certain officers and directors of Unocal at the expense of
its stockholders; and (iii) improperly favoring ChevronTexaco over other
potential bidders by tailoring the merger agreement to ChevronTexaco and
erecting obstacles to deter other interested bidders. In general terms, the
plaintiffs challenge the acquisition price, officer compensation, and the size
of the termination fee contained in the ChevronTexaco merger agreement.
Both lawsuits bring a single claim of breach of fiduciary duties. The first
lawsuit, Lieb v. Unocal et al., seeks only equitable relief by way of an
injunction against the ChevronTexaco merger and an order directing Unocal to
obtain a transaction more favorable to Unocal's stockholders, as well as
attorney's fees. The second lawsuit, Callan v. Unocal et al., seeks similar
equitable relief and fees, as well as an unspecified amount of damages to
Unocal's stockholders sustained as a result of the ChevronTexaco merger. As both
complaints were filed recently, neither lawsuit has progressed beyond initial
written discovery requests. We believe we have substantial meritorious defenses
to the claims.
Tax Matters
We believe we have adequately provided in our accounts for tax items and issues
not yet resolved. Several prior material tax issues are unresolved. Resolution
of these tax issues affects not only the year in which the items arose, but also
our tax situation in other tax years.
With respect to the 1979-1994 taxable years, the Joint Committee on Taxation of
the U.S. Congress reviewed and approved the settlement of all issues for these
years, including the carryback of a 1993 net operating loss to taxable year 1984
and resultant credit adjustments, as previously agreed with the Appeals division
of the Internal Revenue Service ("IRS"). This settlement and corresponding
recalculation of taxable income and credits for this period resulted in an
overpayment of taxes. We received cash refunds of $72 million in 2004 and $6
million in 2005, representing overpaid taxes plus interest thereon. Taxable
years 1979-1984 are now closed and barred from additional assessment of federal
income taxes. Although the IRS has completed its audit of Unocal for taxable
years 1985-1994 and a settlement has been reached for all such years, these
years cannot be formally closed until a separate audit by the IRS of the Alaska
Kuparuk River Unit tax partnership is closed. The Kuparuk tax partnership audit
has been completed and is in the process of being closed. No material
adjustments to taxable income are required. However, until this tax partnership
audit is formally closed, our corporate tax audit remains technically open.
Accordingly, the IRS refers to the 1985-1994 taxable years as "partially
closed." All such developments have been considered in our accounts.
With respect to the 1995-1997 taxable years, a settlement of all issues was
reached with the Appeals division of the IRS. Although the IRS has completed its
audit of Unocal for taxable years 1995-1997 and a settlement has been reached
for all such years, these years cannot be formally closed until a separate audit
by the IRS of the Alaska Kuparuk River Unit tax partnership is closed. The
Kuparuk tax partnership audit has been completed and is in the process of being
closed. No material adjustments to taxable income are required. However, until
this tax partnership audit is formally closed, our corporate tax audit remains
technically open. Accordingly, the IRS refers to the 1995-1997 taxable years as
"partially closed." All such developments have been considered in our accounts.
The 1998-2001 taxable years are before the Exam division of the IRS.
Future Remediation Costs
We have agreed to indemnify certain third parties for particular future
remediation costs that may be incurred for properties held by these parties. The
guarantees were established when we either leased property from or sold property
to these third parties. The properties may or may not have been contaminated by
our former operations. Where it has been or will be determined that we are
responsible for contamination, the guarantees require us to pay the costs to
remediate the sites to specified cleanup levels or to levels that will be
determined in the future.
The maximum potential amount of future payments that we could be required to
make under these guarantees is indeterminate primarily due to the following: the
indefinite term of the majority of these guarantees; the unknown extent of
possible contamination; uncertainties related to the timing of the remediation
work; possible changes in laws governing the remediation process; the unknown
number of claims that may be made; changes in remediation technology; and the
fact that most of these guarantees lack limitations on the maximum potential
amount of future payments.
We have accrued probable and reasonably estimable assessment and remediation
costs for the locations covered under these guarantees. These amounts are
included in the "Company facilities sold with retained liabilities and former
Company-operated sites" category of our reserve for environmental remediation
At March 31, 2005, the reserve for this category totaled $103 million. For those
sites where investigations or feasibility studies have advanced to the stage of
analyzing feasible alternative remedies and/or ranges of costs, we estimate that
$80 million.
BTC Construction Completion Guarantee
We have a construction completion guarantee related to debt financing
arrangements for the BTC crude oil pipeline project. We have an equity interest
in the development of this pipeline from Baku, Azerbaijan through Georgia to the
Mediterranean port of Ceyhan, Turkey. Our maximum potential future payments
under the guarantee are estimated to be $310 million. The debt is secured by
transportation proceeds from production of the Azeri field in the Caspian Sea.
The debt is non-recourse upon financial completion certification, which is
expected by 2009. As of March 31, 2005, we have recorded a liability of $19
million as the estimated value of this guarantee.
Other Guarantees and Indemnities
We have also guaranteed the debt of certain other entities accounted for by the
equity method. The majority of this debt matures ratably through the year 2014.
The maximum potential amount of future payments we could be required to make is
In the ordinary course of business, we have agreed to indemnify cash
deficiencies for certain domestic pipeline joint ventures, which we account for
on the equity method. These guarantees are considered in our analysis of overall
risk. Because most of these agreements do not contain spending caps, it is not
possible to quantify the amount of maximum payments that may be required.
Nevertheless, we believe the payments would not have a material adverse impact
on our financial condition or liquidity.
Financial Assurance for Unocal Obligations
Surety Bonds and Letters of Credit
In the normal course of business, we have performance obligations that are
secured, in whole or in part, by surety bonds or letters of credit. These
obligations primarily cover self-insurance, site restoration, dismantlement and
other programs where governmental organizations require such support. These
surety bonds and letters of credit are issued by financial institutions and are
required to be reimbursed by us if drawn upon. At March 31, 2005, we had
obtained various surety
bonds for $171 million. These surety bonds included a bond for $62 million
securing our performance under a fixed price natural gas sales contract for the
delivery of 72 billion cubic feet of natural gas over a ten-year period that
began in January of 1999 and will end in December of 2008 and $109 million in
various other routine performance bonds held by local, city, state and federal
agencies. We also had obtained $104 million in standby letters of credit at
March 31, 2005, of which $30 million represented letters of credit with the
revenue department in Thailand relating to a tax appeal, $16 million represented
letters of credit for collateral and margin requirements for crude oil and
natural gas purchases and $12 million represented additional collateral related
to the aforementioned bond for the fixed price natural gas sales contract. We
have entered into indemnification obligations in favor of the providers of these
surety bonds and letters of credit.
Other Guarantees and Credit Rating Triggers
We have various other guarantees for approximately $500 million. Approximately
$117 million of the $500 million in guarantees represent financial assurance we
gave on behalf of our Molycorp subsidiary relating to permits covering
operations and discharges from Molycorp's Questa, New Mexico, molybdenum mine.
Our financial assurance is for the completion of temporary closure plans
(required only upon cessation of operations) and other obligations required
under the terms of the permits. The costs associated with the financial
assurance are based on estimations provided by agencies of the state of New
Mexico.
Guarantees for approximately $297 million of the $500 million would require us
to obtain a surety bond or a letter of credit or establish a trust fund if our
credit rating were to drop below investment grade -- that is BBB- or Baa3 from
Standard & Poor's Ratings Services and Moody's Investors Service, Inc.,
Classification on Balance Sheet
Approximately $240 million of the surety bonds, letters of credit and other
guarantees that we are required to obtain or issue reflect obligations that are
already included on the consolidated balance sheet in other current liabilities
and other deferred credits. The surety bonds, letters of credit and other
guarantees may also reflect some of the possible additional remediation
liabilities discussed earlier in this note.
Our lease agreement for the Discoverer Spirit deepwater drillship has a current
minimum daily rate of approximately $229,000. The future remaining minimum lease
payment obligation was $39 million at March 31, 2005. The contract will expire
We also have other contingent liabilities for litigation, claims and contractual
agreements arising in the ordinary course of business. Based on management's
assessment of the ultimate amount and timing of possible adverse outcomes and
associated costs, none of these other matters is presently expected to have a
material adverse effect on our consolidated financial condition, liquidity or
results of operations.
17.  Financial Instruments and Commodity Hedging
Interest rate contracts - We enter into interest rate swap contracts to manage
our debt with the objective of minimizing the volatility and magnitude of our
borrowing costs. We may also enter into interest rate option contracts to
protect our interest rate positions, depending on market conditions. At March
31, 2005, we had approximately $19 million of after-tax deferred losses in
accumulated other comprehensive income on the consolidated balance sheet related
to cash flow hedges of interest rate exposures through September 2012. Of this
amount, approximately $3 million in after-tax losses are expected to be
reclassified to the consolidated earnings statement during the next twelve
Foreign currency contracts - Various foreign exchange currency forward, option
and swap contracts are entered into from time to time to manage our exposures to
adverse impacts of foreign currency fluctuations on recognized obligations and
anticipated transactions. At March 31, 2005, we had no deferred amounts in
to foreign currency contracts.
Commodity hedging activities - We use hydrocarbon derivatives to mitigate our
overall exposure to fluctuations in hydrocarbon commodity prices.
Ineffectiveness for cash flow and fair value hedges was immaterial for the first
three months of 2005. At March 31, 2005, we had $36 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 April 2005 through December 2005. All of the after-tax losses
are expected to be reclassified to the consolidated earnings statement during
the next twelve months.
Fair values for debt and other long-term instruments - The estimated fair values
of our long-term debt and capital leases were $2.96 billion at March 31, 2005.
Fair values were based on the discounted amounts of future cash outflows using
the rates offered to us for debt with similar remaining maturities.
18.  Supplemental Condensed Consolidating Financial Information
Unocal guarantees all the publicly held securities issued by its 100
percent-owned subsidiary Union Oil. Such guarantees are full and unconditional
and no subsidiaries of Unocal or Union Oil guarantee these securities. The
following tables present condensed consolidating financial information for (a)
Unocal (Parent), (b) Union Oil (Parent) and (c) on a combined basis, the
subsidiaries of Union Oil (non-guarantor subsidiaries). Virtually all of our
operations are conducted by Union Oil and its subsidiaries.
CONDENSED CONSOLIDATED EARNINGS STATEMENT
For the Three Months Ended March 31, 2005
Unocal   Union Oil     Guarantor
Millions of dollars                                 (Parent)   (Parent)    Subsidiaries   Eliminations   Consolidated
Sales and operating revenues                           $ -      $ 402          $ 2,008        $ (253)        $ 2,157
Interest, dividends and miscellaneous income             -          7                5            (3)              9
Gain on sales of assets                                  -          -               20             -              20
Total revenues                                     -        409            2,033          (256)          2,186
Purchases, operating and other expenses                  3        301            1,147          (253)          1,198
Depreciation, depletion and amortization                 -         68              208             -             276
Impairments                                              -          -                -             -               -
Dry hole costs                                           -          1               19             -              20
Interest expense                                         1         27                8            (3)             33
Total costs and other deductions                   4        397            1,382          (256)          1,527
Equity in earnings of subsidiaries                     457        444                -          (901)              -
Earnings from equity investments                         -          1               38             -              39
income taxes and minority interests               453        457              689          (901)            698
Income taxes                                            (1)         -              248             -             247
Minority interests                                       -          -                2             -               2
Earnings from continuing operations                    454        457              439          (901)            449
Earnings from discontinued operations                    -          -                5             -               5
Net earnings                                   $ 454      $ 457            $ 444        $ (901)          $ 454
=====================================================================================================================
Millions of dollars                              (Parent)   (Parent)    Subsidiaries   Eliminations   Consolidated
Interest, dividends and miscellaneous income             -          4                8            (1)             11
Gain on sales of assets                                  -         24               20             -              44
Impairments                                              -          3                2             -               5
Dry hole costs                                           -         17                8             -              25
Total costs and other deductions                  10        338            1,320          (207)          1,461
Income taxes                                            (1)       (23)             204             -             180
CONDENSED CONSOLIDATED BALANCE SHEET
Unocal   Union Oil    Guarantor
Millions of dollars                                    (Parent)   (Parent)   Subsidiaries  Eliminations   Consolidated
Cash and cash equivalents                              $ -    $ 1,029          $ 654           $ -         $ 1,683
Accounts and notes receivable - net                    160        261          1,187          (160)          1,448
Inventories                                              -          7            213           (78)            142
Other current assets                                     1         85             38             -             124
Total current assets                                161      1,382          2,092          (238)          3,397
Properties - net                                            -      1,923          6,996            (3)          8,916
Other assets including goodwill                         6,496      5,868            738       (11,725)          1,377
Total assets                                     $6,657    $ 9,173        $ 9,826     $ (11,966)       $ 13,690
======================================================================================================================
Accounts payable                                       $ -      $ 359        $ 1,020        $ (159)        $ 1,220
Current portion of long-term debt                        -        341             87             -             428
Other current liabilities                               54        331            625            (3)          1,007
Total current liabilities                            54      1,031          1,732          (162)          2,655
Long-term debt and capital leases                           -      1,464            838             -           2,302
Deferred income taxes                                       -       (185)         1,034             -             849
Accrued abandonment, restoration
and environmental liabilities                            -        366            534             -             900
Other deferred credits and liabilities                      -        682            399            (3)          1,078
Minority interests                                          -          -             16            12              28
Stockholders' equity                                    6,603      5,815          5,273       (11,813)          5,878
Total liabilities and stockholders' equity       $6,657    $ 9,173        $ 9,826     $ (11,966)       $ 13,690
Cash and cash equivalents                              $ -      $ 691          $ 469           $ -         $ 1,160
Accounts and notes receivable - net                     55        239          1,184           (55)          1,423
Other current assets                                     -        101             26             -             127
Total current assets                                 55      1,039          1,968          (132)          2,930
Accounts payable                                       $ -      $ 278        $ 1,074         $ (54)        $ 1,298
Current portion of long-term debt                      242        162             87             -             491
Other current liabilities                               54        244            496            (2)            792
Total current liabilities                           296        684          1,657           (56)          2,581
Deferred income taxes                                       -       (156)           995             -             839
Other deferred credits and liabilities                      -        663            309            (3)            969
CONDENSED CONSOLIDATED CASH FLOWS
Unocal   Union Oil   Guarantor
Millions of dollars                                    (Parent)  (Parent)   Subsidiaries  Eliminations   Consolidated
Net cash provided by operating activities               $ (28)    $ 403          $ 533           $ -           $ 908
Capital expenditures and acquisitions
(includes dry hole costs)                             -       (67)          (352)            -            (419)
Proceeds from sales of assets
and discontinued operations                           -         7             89             -              96
Net cash used in investing activities                       -       (60)          (263)            -            (323)
Change in long-term debt                               (14)       (5)           (83)            -            (102)
Dividends paid on common stock                         (53)        -              -             -             (53)
Proceeds from issuance of common stock                  95         -              -             -              95
Other                                                    -         -             (2)            -              (2)
Net cash provided by (used in) financing activities        28        (5)           (85)            -             (62)
Increase in cash and cash equivalents                       -       338            185             -             523
Cash and cash equivalents at beginning of period            -       691            469             -           1,160
Cash and cash equivalents at end of period                $ -   $ 1,029          $ 654           $ -         $ 1,683
Net cash provided by operating activities                 $ -     $ 523          $ 227           $ -           $ 750
and discontinued operations                           -        20             52             -              72
Return of capital from affiliate company                 -         -             52             -              52
Change in long-term debt                                 -      (193)            36             -            (157)
Net cash provided by (used in) financing activities        (1)     (193)            36             -            (158)
Increase (decrease) in cash and cash equivalents           (1)      287             70             -             356
Cash and cash equivalents at beginning of period            1        45            358             -             404
Cash and cash equivalents at end of period                $ -     $ 332          $ 428           $ -           $ 760
19.  Segment Data
Our reportable segments are: (1) Exploration and Production, (2) Midstream and
Marketing, and (3) Geothermal. General corporate overhead, unallocated costs and
other miscellaneous operations, including real estate, carbon and minerals and
those businesses that were sold or being phased-out, are included under the
Corporate and Other heading.
Segment Information                                       Exploration and Production
For the Three Months                              North America             International
Ended March 31, 2005                                                                                Total
Millions of dollars                         U.S.      Canada  Total N.A. Asia    Other  Total Intl     E&P
Sales & operating revenues                $ 304        $ 84     $ 388   $ 459     $ 98    $ 557     $ 945
Other income (loss) (a)                       4           -         4      (9)       7       (2)        2
Inter-segment revenues                      252          37       289     173        -      173       462
Total                                       560         121       681     623      105      728     1,409
Earnings from equity investments              -           -         -      13        -       13        13
Earnings (loss) from continuing operations  154          18       172     251       48      299       471
Earnings from discontinued operations (net)   -           -         -       -        -        -         -
Net earnings (loss)                         154          18       172     251       48      299       471
Assets (at March 31, 2005)                3,283       1,377     4,660   3,787    1,070    4,857     9,517
Midstream   Geothermal         Corporate and Other           Total
and                             Net   Environ-
Marketing               Admin &  Interest mental &
(b)                  General  Expense Litigation Other(c)
Sales & operating revenues              $ 1,135        $ 43       $ -     $ -      $ -     $ 34   $ 2,157
Other income (loss) (a)                       2           1         -       8        -       16        29
Inter-segment revenues                        4           -         -       -        -     (466)        -
Total                                     1,141          44         -       8        -     (416)    2,186
Earnings from equity investments             16           -         -       -        -       10        39
Earnings (loss) from continuing operations   35          17       (29)    (15)     (12)     (18)      449
Earnings from discontinued operations (net)   -           -         -       -        -        5         5
Net earnings (loss)                          35          17       (29)    (15)     (12)     (13)      454
Assets (at March 31, 2005)                1,281         504         -       -        -    2,388    13,690
(a)Includes interest, dividends and miscellaneous income, and gain (loss) on sales of assets.
(b)Includes $163 million of crude oil buy/sell transactions settled in cash in sales & operating revenues.
(c)Includes eliminations and consolidation adjustments.
Other income (loss) (a)                      10           -        10       1        1        2        12
Total                                       515         103       618     455       58      513     1,131
Earnings from discontinued operations (net)   3           -         3       -        -        -         3
Assets (at December 31, 2004)             3,307       1,376     4,683   3,661    1,007    4,668     9,351
Midstream   Geothermal          Corporate and Other          Total
and                              Net   Environ-
Sales & operating revenues                $ 980        $ 40       $ -     $ -      $ -     $ 22   $ 1,821
Other income (loss) (a)                       5          32         -       6        -        -        55
Total                                       987          72         -       6        -     (320)    1,876
Earnings from equity investments             16           1         -       -        -       10        37
Earnings from discontinued operations (net)   -           -         -       -        -       (1)        2
Assets (at December 31, 2004)             1,303         573         -       -        -    1,874    13,101
20.  Subsequent Event
On April 4, 2005, we entered into a merger agreement with ChevronTexaco
Corporation ("ChevronTexaco") and Blue Merger Sub Inc., a direct wholly-owned
subsidiary of ChevronTexaco. The merger agreement provides that, upon the terms
and subject to the conditions set forth in the merger agreement, Unocal will
merge with and into Blue Merger Sub, with Blue Merger Sub continuing as the
surviving corporation and a wholly-owned subsidiary of ChevronTexaco. The
aggregate consideration that Unocal stockholders will receive in the merger is
structured as 75 percent stock and 25 percent cash. Unocal stockholders may
elect to receive either 1.03 shares of ChevronTexaco stock, or $65 in cash or
the combination of $16.25 in cash and 0.7725 of a share of ChevronTexaco common
stock for each share of Unocal common stock; however, these elections will be
subject to proration to preserve the overall mix of 75 percent of Unocal common
stock being exchanged for ChevronTexaco common stock and 25 percent of Unocal
common stock being exchanged for cash.
Consummation of the merger is subject to customary conditions, including
approvals by our stockholders and certain regulatory agencies, such as the U.S.
Federal Trade Commission ("FTC"). For additional information regarding the
pending acquisition, refer to our current reports on Form 8-K, as amended, filed
with the SEC on April 4 and April 7, 2005, and "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Pending Merger with
ChevronTexaco" in Item 2 of this report.
ITEM 2.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
You should read the following discussion and analysis of our financial condition
and results of operations in conjunction with Management's Discussion and
Analysis in Item 7 of our 2004 10-K and the consolidated financial statements
and related notes therein. Our 2004 10-K contains a discussion of other matters
not included herein, such as disclosures regarding critical accounting policies
and estimates, contractual obligations and our credit facilities and other
financing sources. You should read the following discussion and analysis
together with the cautionary statement under "Forward-Looking Statements" on
page iii of this report.
PENDING MERGER WITH CHEVRONTEXACO
Corporation and Blue Merger Sub Inc., a direct wholly-owned subsidiary of
ChevronTexaco. The following description of the merger and the merger agreement
does not purport to be complete and is qualified in its entirety by reference to
the merger agreement, which has been filed as Exhibit 2.1 to our Form 8-K filed
on April 7, 2005.
The merger agreement provides that, upon the terms and subject to the conditions
set forth in the merger agreement, Unocal will merge with and into Blue Merger
Sub and thereafter become a wholly-owned subsidiary of ChevronTexaco.
In the merger, each share of Unocal common stock issued and outstanding
immediately prior to the effective time of the merger (other than shares as to
which appraisal rights are properly asserted under Delaware law and shares owned
by Unocal, ChevronTexaco or their respective wholly owned subsidiaries) will be
converted into and become exchangeable, subject to proration as described below,
for either:
o 1.03 shares of ChevronTexaco common stock, or
o $65.00 in cash, or
o the combination of $16.25 in cash and 0.7725 of a share of
ChevronTexaco common stock,
as elected by holders of Unocal common stock. This election by holders of Unocal
common stock is subject to the limitation that 75 percent of the outstanding
shares of Unocal common stock will be exchanged for ChevronTexaco common stock
and 25 percent of the outstanding shares of Unocal common stock will be
exchanged for cash, with proration to be applied in the event of
oversubscription.
As explained in our Form 8-K, filed on April 7, 2005, ChevronTexaco and Unocal
have made customary representations and warranties in the merger agreement,
which have been made solely for the benefit of the other party to the merger
agreement and should not be relied on by any other person.
ChevronTexaco and Unocal have also made customary covenants and agreements in
the merger agreement, including, among others, covenants:
o   that we will conduct our business in the ordinary course consistent
with past practice during the interim period between the execution of
the merger agreement and consummation of the merger,
o that we will not engage in certain kinds of transactions during such
interim period,
o that we will cause a stockholders' meeting to be held to consider
approval of the merger and the other transactions contemplated by the
merger agreement, and
o that, subject to certain exceptions, our board of directors will
recommend adoption by our stockholders of the merger agreement.
In addition, we made certain additional customary covenants, including, among
others, covenants not to: (i) solicit proposals relating to alternative business
combination transactions or (ii) subject to certain exceptions, enter into
discussions concerning, or provide confidential information in connection with,
any proposals for alternative business combination transactions.
Consummation of the merger is subject to customary conditions, including:
o approval of the transaction by our stockholders,
o absence of any law or order prohibiting the completion of the merger,
o expiration or termination of the Hart-Scott-Rodino waiting period and
certain other regulatory approvals,
o subject to certain exceptions, the accuracy of the representations
and warranties of the other party,
o material compliance of the other party with its covenants, and
o the delivery of customary opinions from counsel to Unocal and counsel
to ChevronTexaco that the merger will qualify as a tax-free
reorganization for federal income tax purposes.
The merger agreement contains certain termination rights for both ChevronTexaco
and Unocal, and further provides that, upon termination of the merger agreement
under specified circumstances, Unocal may be required to pay ChevronTexaco a
termination fee of up to $500,000,000.
Our primary line of business is the exploration, development and production of
natural gas, crude oil, condensate and natural gas liquids. Our principal
operations are in North America and Asia. We are also a leading producer of
geothermal energy in Asia. Other activities include ownership in proprietary and
common carrier pipelines, natural gas storage facilities and the marketing of
hydrocarbon commodities. Fluctuations in hydrocarbon commodity prices and the
resulting impact on our realized prices for liquids and North America natural
gas are a significant driver of our financial performance.
Some of our more significant operational highlights and other activities from
the first quarter of 2005 are listed below:
o began crude oil and natural gas production from the Mad Dog field in the Gulf
of Mexico in January 2005,
o began production in February from Phase 1 of the ACG crude oil project in the
Azerbaijan sector of the Caspian Sea and continued progress on Phase 2 and 3
of the project,
o began natural gas production in March 2005 from the Moulavi Bazar field in
o encountered hydrocarbons in an appraisal well drilled on the deepwater Mad Dog
Southwest Ridge in the Gulf of Mexico, which was further delineated by three
sidetracks, and
o completed the redemption of our outstanding 6-1/4% convertible junior
subordinated debentures.
Commodity Prices and Operating Results
We continued to benefit from upward trending commodity prices during the first
quarter of 2005. Our worldwide production increased by 5 percent in the first
quarter of 2005 compared to the first quarter of 2004 primarily due to increased
production from the West Seno project in Indonesia. Rising production costs will
remain a challenge throughout the year as the entire service industry attempts
to benefit from the higher commodity price environment through pricing
increases.
The following table summarizes our net daily production and average prices for
our North America and International Exploration and Production business units:
2005      2004
U.S.                                                          57        55
Canada                                                        16        17
Total liquids                                            73        72
U.S.                                                         456       515
Total natural gas                                       539       599
North America Average Prices (excluding hedging activities) (a)
U. S.                                                    $ 44.72   $ 32.66
Canada                                                   $ 38.31   $ 28.51
Average                                             $ 43.35   $ 31.71
U. S.                                                    $  5.26   $  5.04
Canada                                                   $  5.69   $  5.38
Average                                             $  5.32   $  5.09
North America Average Prices (including hedging activities) (a)
(a)  Excludes gains/losses on derivative positions not accounted for as hedges
and ineffective portions of hedges.
Liquids  (thousand barrels)
Asia                                                         76         66
Other (b)                                                    20         20
Total liquids                                           96         86
Asia                                                      1,011        884
Total natural gas                                    1,021        909
Asia                                                     $45.50    $ 31.44
Other                                                    $47.57    $ 32.12
Average                                             $45.93    $ 31.57
Asia                                                     $ 3.40    $  2.97
Other                                                    $ 5.26    $  4.29
Average                                             $ 3.41    $  2.98
Worldwide Net Daily Production (b)
Liquids  (thousand barrels)                                    169        158
Natural gas - dry basis (million cubic feet)                 1,560      1,508
Barrels oil equivalent (thousands)                             429        409
Worldwide Average Prices (excluding hedging activities) (d)
Liquids (per barrel)                                        $44.80    $ 31.64
Natural gas (per mcf)                                       $ 4.08    $  3.83
Worldwide Average Prices (including hedging activities) (d)
(a)  International production is presented utilizing the economic interest
(b)  Includes proportional interests in production of equity investees of:
Liquids         -          1
Natural gas         -         15
Barrels oil equivalent         -          4
(c)  International did not have any hedging activities.
(d)  Excludes gains/losses on derivative positions not accounted for as hedges
Our consolidated results are driven primarily by the results of our oil and gas
exploration and production business segment. The following discussion and
analysis of our consolidated financial condition and results of operations
should be read in conjunction with the historical financial information provided
in the consolidated financial statements and accompanying notes in Item 1 of
this report and in Item 8 of our 2004 10-K. Our financial performance is highly
dependent on commodity prices, our exploration success and our ability to
develop and produce our proved reserves. Other factors such as, but not limited
to, asset sales, insurance settlements, environmental and litigation costs may,
from time to time, be important factors that impact our financial performance.
The following table summarizes our consolidated net earnings for the quarters
ended March 31, 2005 and 2004:
Millions of dollars                                           2005         2004
Earnings from continuing operations                          $ 449        $ 267
Earnings from discontinued operations                            5            2
Net earnings                                                 $ 454        $ 269
1st quarter earnings in 2005 increased $182 million, or 68 percent, vs. 1st
quarter 2004 primarily due to the following factors:
o Higher worldwide commodity prices in 2005 increased net earnings by
approximately $170 million.
o International production was higher in 2005 and contributed about $24 million
in higher earnings, primarily from the West Seno project in Indonesia and our
Thailand operations.
o Lower net interest expense due primarily to lower debt levels increased net
earnings by approximately $15 million.
o After-tax environmental and litigation expenses were $13 million in 2005,
compared with $23 million in 2004.
o Higher margins from our North America natural gas storage business increased
net earnings by $12 million.
o Higher molybdenum margins from our minerals business increased net earnings
by $11 million.
Negative Variance Factor
o Lower North America natural gas production reduced net earnings by about $20
million in 2005 due primarily to natural production declines.
Earnings from discontinued operations were $5 million and $2 million in the
first quarters of 2005 and 2004, respectively. The first quarter of 2005
included an after-tax gain of $2 million related to the 1997 sale of our former
West Coast refining, marketing and transportation assets. In addition, our
needle coke business is classified as discontinued operations (see note 10 in
Item 1 of this report). After-tax earnings from this business were $3 million
and a loss of $1 million in the first quarters of 2005 and 2004, respectively.
The first quarter of 2004 also included approximately $3 million after-tax from
our operations in certain mineral fee producing properties that were sold in the
second quarter of 2004.
1st quarter  sales and  operating  revenues in 2005  increased by $336  million,
or 18 percent,  vs. 1st quarter 2004 primarily due to the following factors:
o Higher average commodity prices from our exploration and production
activities increased sales revenues. Our worldwide average realized liquids
price was $44.72 per Bbl, which was an increase of $14.08 per Bbl, or 46
percent, from 2004. Our average realized liquids price included losses from
our hedging activities of 8 cents and $1.00 per Bbl in 2005 and 2004,
respectively. Our worldwide average realized natural gas price was $4.28
per Mcf in 2005, which was an increase of 28 cents per Mcf, or 7 percent,
from the $4.00 per Mcf, realized in 2004. Our average worldwide natural gas
price included gains from our hedging activities of 20 cents and 17 cents
per Mcf in 2005 and 2004, respectively.
o Sales and operating revenues from marketing activities were $895 million in
the first quarter of 2005, compared with $833 million in the same period a
year ago.  During the first quarters of 2005 and 2004, approximately 21
attributable to the resale of crude oil, natural gas and natural gas liquids
purchased from outside parties by our Midstream and Marketing segment.
These percentages in both periods included crude oil buy/sell transactions.
Crude oil buy/sell amounts were primarily lower due to a significant decrease
of volumes associated with these transactions, which was partially offset by
higher crude oil prices (see crude oil buy/sell discussions in Item 8 of our
2004 10-K in the consolidated financial statements under notes 1 and 2).
These marketing activities allowed us to better manage commodity-related risk
by effectively transferring commodities from production locations to industry
o Higher International production increased sales revenues by approximately
$70 million primarily due to increased production from the West Seno field
in Indonesia and higher Thailand natural gas production compared to the
first quarter of 2004.
o In North America, lower natural gas production reduced sales revenues by
approximately $30 million. Most of the decline in the first quarter of 2005
was due to natural field declines.
2005 was $247 million compared with $180 million for the first quarter of 2004.
The effective income tax rate for the first quarter of 2005 was 35 percent
compared with 40 percent for the first quarter of 2004. The overall lower
the sale of Unocal Bharat in the first quarter of 2005 (see note 4 in Item I of
Part I of this report).
See note 19 to the consolidated financial statements in Item 1 of this report
for additional details on our reportable segments. The following business
segment results should be read in conjunction with the historical financial
information provided in the consolidated financial statements and accompanying
notes in Item 8 of our 2004 10-K, the consolidated results discussed earlier in
this Item 2 and the business and properties descriptions in Items 1 and 2 of our
2004 10-K. Our operations are organized in the following business segments:
North America - Included in this category are our oil and gas operations in the
United States and Canada.
Earnings from continuing operations totaled $172 million in the first quarter of
2005 compared to $125 million for the same period a year ago, which was an
increase of $47 million. Higher natural gas and liquids prices contributed $75
million in higher earnings in the first quarter of 2005 compared with the same
quarter a year ago. The positive impact from higher prices was offset by lower
natural gas production in the first quarter of 2005 compared with the same
period a year ago, which reduced after-tax earnings by approximately $20
million. North America natural gas production averaged 539 MMcf/d down from 599
MMcf/d in 2004. Most of the natural gas production decline was due to natural
field declines primarily in the Gulf of Mexico.
International - Our International operations encompass oil and gas exploration
and production activities outside of North America. Through our International
subsidiaries, we operate or participate in production operations in Thailand,
Indonesia, Myanmar, Bangladesh, the Netherlands, Azerbaijan and the Democratic
Republic of Congo.
2005 compared to $175 million in the first quarter of 2004. The increase was
primarily due to higher liquids and natural gas prices, which increased net
earnings by approximately $80 million and $15 million, respectively. In
addition, higher production principally from Indonesia and Thailand contributed
approximately $25 million to after-tax earnings. International liquids
production averaged 96 MBbl/d in the current quarter, up from 86 MBbl/d a year
ago, while natural gas production averaged 1,021 MMcf/d up from 909 MMcf/d in
the same period a year ago.
The Midstream and Marketing segment is comprised of our equity interests in
certain petroleum pipeline companies in the United States and Argentina,
wholly-owned pipelines and terminals throughout the United States, our North
America natural gas storage business and the organization that markets the
majority of our worldwide liquids production and North American natural gas
production. To market our U.S. production, the segment enters into various sale
and purchase transactions, including crude oil buy/sell transactions, with
unaffiliated oil and gas producing, refining, marketing and trading companies
(see crude oil buy/sell discussions in the consolidated financial statements
under notes 1 and 2). These transactions effectively transfer the commodities
from production locations to industry marketing centers with higher volumes of
commercial activity and greater market liquidity. These transactions allow us to
better manage our commodity-related risks. Currently, these sale and purchase
transactions represent a significant portion of the segment's U.S. crude oil
sales and purchases. This marketing organization is also responsible for
implementing commodity specific risk management activities on behalf of our
exploration and production segment, and it conducts our trading activities
involving hydrocarbon derivative instruments.
Earnings from continuing operations totaled $35 million in the current quarter
compared to $23 million in the first quarter of 2004. The results for the
current quarter reflect improved results from our natural gas storage business
which added $12 million to net earnings.
The segment's sales and operating revenues were $1,135 million in the current
quarter compared to $980 million in the same quarter a year ago. Included in
these totals were sales from marketing activities totaling $895 million in the
current quarter compared to $833 million in the same quarter a year ago,
representing approximately 41 percent and 46 percent of our total sales and
operating revenues for the first quarters of 2005 and 2004, respectively. Sales
from marketing activities include buy/sell transactions. The increase in sales
from marketing activities was primarily due to higher liquids and natural gas
prices and increased sales volumes from gas storage.
The Geothermal segment includes geothermal steam production for power
generation, with operations in the Philippines and Indonesia. Geothermal
activities also include the operation of geothermal steam-fired power plants in
Indonesia and equity interests in natural gas-fired power plants in Thailand.
compared to $37 million in the same period a year ago. The first quarter of 2004
included an after-tax gain of $21 million from the sale of our rights and
interests in the Sarulla geothermal project on the island of Sumatra, Indonesia.
Corporate and Other includes general corporate overhead, miscellaneous
operations (including real estate, carbon and mineral businesses), other
corporate unallocated costs (including environmental and litigation expenses)
and net interest expense.
The results from continuing operations for the current quarter were a loss of
$74 million compared to a loss of $94 million in the same period a year ago. Net
interest expense for the current quarter was $15 million compared to $32 million
in the same quarter a year ago. After-tax expenses for environmental and
litigation matters for the current quarter were $13 million compared to $20
million in the same quarter a year ago. The current quarter reflected $8 million
after-tax in higher results from our minerals business due primarily to higher
margins attributable to molybdenum prices.
Cash and cash equivalents on hand totaled $1.68 billion at March 31, 2005, up
from $1.16 billion at the end of 2004. As discussed earlier under "--Pending
Merger with ChevronTexaco," we have agreed in our merger agreement with
ChevronTexaco, among other things, that we will not engage in certain kinds of
transactions during the interim period between the execution of the agreement
and the consummation of the merger, including limitations on our ability to
incur debt, issue securities and sell material assets. If we were to seek to
engage in a restricted activity under these covenants, we would be required to
obtain the prior consent of ChevronTexaco. Based on current commodity prices and
current development projects, we do not anticipate that these contractual
limitations will materially adversely affect our ability to satisfy our
liquidity needs during this interim period and we expect that cash generated
from operating activities, routine asset sales and cash on hand will be
sufficient in 2005 to cover our operating and capital spending requirements, to
make expected dividend payments and to pay down scheduled debt. In addition, we
believe that our available borrowing capacity is sufficient to enable us to meet
unanticipated cash requirements if needed.
Cash flows from operating activities was $908 million for the quarter ended
March 31, 2005, compared with $750 million for the same period a year ago. The
increase principally reflected the effects of higher worldwide commodity prices.
Capital Expenditures and Other Investing Activities
Capital expenditures were $419 million for the first quarter of 2005 compared
with $360 million in the same period a year ago. The current period results
reflected $30 million in higher U.S. expenditures and $25 million in higher
International expenditures.
Asset Sales
Pre-tax proceeds from asset sales relating to continuing and discontinued
operations were $96 million for the three month period ended March 31, 2005. The
current year included pre-tax proceeds of $26 million from the sale of a
subsidiary that held our equity interest in an exploration and production
company in India. Our Molycorp subsidiary sold down its equity investment in a
niobium operation in Brazil, from 40 percent to 35 percent for pre-tax proceeds
of $31 million in cash. We also received pre-tax proceeds of $39 million from
the sale of other miscellaneous assets and real estate properties.
Pre-tax proceeds from asset sales were $72 million for the three months ended
March 31, 2004. We received $60 million from the sale of our rights and
interests in the Sarulla geothermal project in Indonesia. We also received $12
million from the sale of various other properties, primarily in the Gulf of
the first quarter of 2005, we paid the Trust a combination of cash and Unocal
common stock to retire the $242 million outstanding balance of the 6-1/4%
convertible junior subordinated debentures (see note 14 for further detail).
We also paid $77 million as full payment under the revolving portion of our
Canadian dollar-denominated credit agreement. In addition, we paid $5 million
in medium term notes that matured in the first quarter of 2005.
In the first quarter of 2005, we received $95 million from the issuance of
2,788,862 shares of our common stock related to the exercise of existing stock
Off-Balance Sheet Arrangements - Sales of Accounts Receivables
Through a bankruptcy remote wholly-owned subsidiary, Unocal Receivables
Corporation ("URC"), we had a sales agreement with an outside unrelated party
that provides for the sale of up to $125 million of an undivided interest in
domestic crude oil and natural gas trade receivables. We used this program as a
low cost and readily available source of working capital. Details of this
arrangement are provided in note 11 to the consolidated financial statements in
Item 8 of our 2004 10-K. At March 31, 2005, we had no outstanding balance under
this program. We terminated this program effective April 15, 2005.
We are committed to operating our business in a manner that is environmentally
responsible. This commitment is fundamental to our core values. As part of this
commitment, we have procedures in place to audit and monitor our environmental
performance. In addition, we have implemented programs to identify and address
environmental risks throughout our company.
Probable costs associated with identified and reasonably estimable environmental
obligations have been accrued in a reserve for such obligations. Accruals are
based on developments to date, our estimates of the outcomes of these matters
and our experience in addressing these matters. As the scope of the liabilities
becomes better defined, there will be changes in the estimates of future costs,
which could have a material effect on our future results of operations,
financial condition or liquidity. At March 31, 2005, our reserves for
environmental remediation obligations totaled $243 million, of which $114
million was included in current liabilities. During the first quarter of 2005,
cash payments of $17 million were applied against the reserves and $16 million
was added to the reserves. We may also incur additional liabilities at sites
where remediation liabilities are probable but future environmental costs are
not presently reasonably estimable because the sites have not been assessed or
the assessments have not advanced to stages where costs are reasonably
aggregating approximately $225 million.
The reserve amounts and estimated possible additional costs are grouped into the
following four categories:
See notes 15 and 16 to the consolidated financial statements in Item 1 of this
report for additional information on environmental related matters.
In the first quarter of 2005, we recorded provisions of $12 million for the
"Company facilities sold with retained liabilities and former Company-operated
sites" category. These provisions were primarily for sites that may have been
contaminated by our former operations. The provisions were based on new and
revised cost estimates that we identified during the first three months of 2005
for the remediation of approximately 55 service station, bulk plant and terminal
sites and for the assessment and remediation of oil and gas fields in Central
California.
In the first three months of 2005, our estimated possible additional remediation
costs increased by $10 million for the "Company facilities sold with retained
liabilities and former Company-operated sites" category. This increase was
primarily for the cost of remediation that may be needed at oil and gas fields
in Central California that we formerly operated.
We are also subject to contingent liabilities for existing and potential claims,
lawsuits and other proceedings and tax and other matters. For a more detailed
discussion on these matters, see Item 3 in Part I and note 23 to the
consolidated financial statements included in Item 8 of Part II of our 2004 Form
10-K and Item 1 in Part II and note 16 to the interim financial statements
included in Item 1 of Part I of this report.
The following operations outlook is based upon our current expectations and
beliefs. These statements are subject to a number of known and unknown risks and
uncertainties that could cause actual results to differ materially from those
described, including the timing and effect of the anticipated consummation of
our merger with ChevronTexaco or the effect on us if the merger is not
consummated. Please see the cautionary statement under "Forward-Looking
Statements" on page iii of this report and the "Risk Factors" in Item 7 of Part
II of our 2004 10-K. This outlook discusses our current expectations regarding
certain important operational activities for the remainder of 2005 and for other
future time periods. It is not intended to be a complete discussion of all
future operational activities.
Our profitability will continue to be significantly affected by crude oil and
natural gas commodity prices. We expect energy prices to remain volatile for the
remainder of 2005 due to a variety of fundamental and market perception factors
including variability of the weather on a year-to-year basis, worldwide demand,
crude oil and natural gas inventory levels, production quotas set by OPEC,
current and future worldwide political instability, worldwide security and other
factors. We have secured fixed price "hedges" to seek to mitigate some of that
volatility, primarily relating to a portion of our 2005 North America natural
gas and crude oil production.
In the first quarter of 2005, we initiated production from the first three major
projects in our 2005 development pipeline - Mad Dog in the deepwater Gulf of
Mexico, Phase 1 of the ACG crude oil project in the Azerbaijan sector of the
Caspian Sea, and the Moulavi Bazar field in Bangladesh. We expect two other key
development projects to move forward on schedule and begin production in 2005 -
the K-2 field in the deepwater Gulf of Mexico and Phase 2 of the Thailand crude
oil project.
Exploration and Production - North America
o The Mad Dog field in the Gulf of Mexico, operated by BP, began production
in January 2005. The K-2 field in the Gulf of Mexico, operated by Eni, is
expected to begin production in the second quarter of 2005. The estimate of
our net production for both the Mad Dog field and K-2 fields combined is
expected to average about 4 MBOE/d to 6 MBOE/d in the second quarter of
2005, 8 MBOE/d to 10 MBOE/d in the third quarter of 2005, rising to an
average of 10 MBOE/d to 12 MBOE/d in the fourth quarter of 2005. We have a
15.6 percent working interest in the Mad Dog field and a 12.5 percent
working interest in the K-2 field.
o Our deepwater Gulf of Mexico exploration and appraisal program continues in
2005.  We are currently drilling the Knotty Head prospect in Green Canyon
Block 512, a Miocene test, where we are drilling the well for the operator of
record and have a 25 percent working interest in the well.  Following Knotty
Head, we plan to drill the St. Malo #3 well, which is an appraisal well to our
2003 St. Malo discovery in the Walker Ridge area.  In addition, we are
currently participating in drilling a Miocene test on the Chilkoot prospect in
Green Canyon Block 320, operated by Kerr McGee Corporation.  We also plan to
participate in a follow-up well on the Puma discovery in Green Canyon Block
823 and Mad Dog Deep, a Paleogene test, in Green Canyon Block 826, both
operated by BP, in the second quarter of 2005.
Exploration and Production - International
o Thailand's electricity market is expected to continue growing in 2005.
Additional supplies of natural gas to meet that growth have been
constrained by pipeline capacity. De-bottlenecking activities on the two
existing pipelines in the Gulf of Thailand should allow us an opportunity
for increased production in 2005, prior to the expected completion of a
third pipeline in 2006.
o Start up of the Phase 2 development of the Thailand crude oil project is
expected late in the second quarter of 2005 or early in the third quarter
of 2005 with production ramping up to peak capacity by late third quarter.
The average net production rate from Phase 2 is expected to be between 7
MBOE/d and 9 MBOE/d in the third quarter of 2005 and between 9 MBOE/d and
11 MBOE/d in the fourth quarter of 2005.
o Development engineering and planning is continuing for multiple oil and gas
discoveries in the deepwater Kutei Basin. The development strategy is to
install two new deepwater production processing hubs, one at Gendalo and
one at Gehem. These hubs will process oil and gas production for multiple
satellite developments. The initial plans of development for both hubs are
currently being prepared for submission to partners and the Government of
o We are also continuing to work on our evaluation for development
feasibility at the Sadewa field, which is a candidate for early natural gas
development because of its proximity to the shelf. Concept selection work
has been completed and detailed design work has begun. The development
concept is a natural gas and crude oil development from a shallow-water
platform with extended reach wells towards targets in deep water.
o First production from the Moulavi Bazar field began in March 2005. This new
field is expected to increase our net average production over 2004 levels
in the country by 20 MBOE/d to 24 MBOE/d in the second quarter and 20 MBOE/d
to 32 MBOE/d in the third quarter of 2005. This production outlook reflects
higher volumes due partially to an increase in cost recovery that we expect
to receive from the Jalalabad field because of new production from the Moulavi
Bazar field. We anticipate the net average incremental production over 2004
levels in the fourth quarter of 2005 to be 9 MBOE/d to 15 MBOE/d due to the
completion of cost recovery.
o Work continues to progress at the Bibiyana field which is planned to be
developed in stages to provide Bangladesh with natural gas resources in the
short, medium and long-term time frames. We currently expect first
production by the end of 2006.
o First production from Phase 1 of the ACG crude oil project began in the
first quarter of 2005. Phase 1 is expected to deliver net average production
of 5 MBOE/d to 7 MBOE/d in the second quarter of 2005 and 10 MBOE/d to 13
MBOE/d in the third and fourth quarters of 2005.  Development on Phases 2
and 3 of the ACG crude oil project will continue in 2005. We have a 10.28
percent working interest in the AIOC project.
In parallel with the ACG crude oil project, the BTC crude oil pipeline is
expected to be fully operational in the second half of 2005. The portions of the
pipeline through Azerbaijan and Georgia are expected to be complete and ready
for line-fill in the second quarter of 2005. The BTC pipeline will transport the
crude oil from the ACG crude oil project to the Turkish port of Ceyhan and will
have a capacity of 1 million Bbl/d. Our interest in this pipeline is 8.9
percent.
See note 2 to the consolidated financial statements for information about recent
accounting pronouncements.
ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
We are exposed to market risks, which may give rise to losses from adverse
changes in market prices and rates. The primary market risks to which we are
exposed are: (1) commodity prices, (2) interest rates and (3) foreign currency
exchange rates.
As part of our overall risk management strategies, we use derivative financial
instruments to manage and seek to reduce risks associated with these factors. We
also trade hydrocarbon derivative instruments, such as futures contracts, swaps
and options to exploit anticipated opportunities arising from commodity price
fluctuations. To the extent that we engage in hedging activities to seek to
protect ourselves from commodity price volatility, we may be prevented from
realizing the benefits of price increases above the levels of the hedges. In
addition, speculative trading in hydrocarbon commodities and derivative
instruments in connection with our risk management activities subjects us to
additional risk.
We determine the fair values of our derivative financial instruments primarily
based upon market quotes of exchange traded instruments. Most futures and
options contracts are valued based upon direct exchange quotes or industry
published price indices. Some instruments with longer maturity periods require
financial modeling to accommodate calculations beyond the horizons of available
exchange quotes. These models calculate values for outer periods using current
exchange quotes (i.e., forward curve) and assumptions regarding interest rates,
commodity and interest rate volatility and, in some cases, foreign currency
exchange rates. While we feel that current exchange quotes and assumptions
regarding interest rates and volatilities are appropriate factors to measure the
fair value of our longer termed derivative instruments, other pricing
assumptions or methodologies may lead to materially different results in some
instances.
Commodity Price Risk - We are a producer, purchaser, marketer and trader of
certain hydrocarbon commodities such as crude oil and condensate, natural gas
and refined products and are subject to the associated price risks. We use
hydrocarbon price-sensitive derivative instruments ("hydrocarbon derivatives"),
such as futures contracts, swaps, collars and options, to mitigate our overall
exposure to fluctuations in hydrocarbon commodity prices. We may also enter into
hydrocarbon derivatives to hedge contractual delivery commitments and future
crude oil and natural gas production against price exposure. We also actively
trade hydrocarbon derivatives, primarily exchange regulated futures and options
contracts, subject to internal policy limitations.
We use a variance-covariance value at risk model to assess the market risk of
our hydrocarbon derivatives. Value at risk represents the potential loss in fair
value we would experience on our hydrocarbon derivatives, as a result of
commodity price changes using calculated volatilities and correlations over a
specified time period with a given confidence level. Our risk model is based
upon current market data and uses a three-day time interval with a 97.5 percent
confidence level. The model includes offsetting physical positions for any
existing hydrocarbon derivatives related to our fixed price pre-paid crude oil
and pre-paid natural gas sales. The model also includes our net interests in our
subsidiaries' crude oil and natural gas hydrocarbon derivatives and forward
sales contracts. Based upon our risk model, the value at risk related to
hydrocarbon derivatives held for hedging purposes was $24 million at March 31,
2005. Value at risk related to hydrocarbon derivatives held for non-hedging
purposes was $1 million at March 31, 2005. See "Hydrocarbon Derivatives Tables."
Interest Rate Risk - From time to time, we temporarily invest our excess cash in
short-term interest-bearing securities issued by high-quality issuers. Our
policies limit the amount of investment in securities of any one financial
institution. Due to the short time the investments are outstanding and their
general liquidity, these instruments are classified as cash equivalents in the
consolidated balance sheet and do not represent a material interest rate risk to
us. Our primary market risk exposure to changes in interest rates relates to our
long-term debt obligations. We manage our exposure to changing interest rates
principally with a combination of fixed and floating rate debt. Interest rate
risk sensitive derivative financial instruments, such as swaps or options, may
also be used depending upon market conditions.
We evaluated the potential effect that near term changes in interest rates would
have had on the fair value of our interest rate risk sensitive financial
instruments at March 31, 2005. Assuming a ten percent decrease in our weighted
average borrowing costs at March 31, 2005, the potential increase in the fair
value of our debt obligations and associated interest rate derivative
instruments, including the debt obligations and associated interest rate
derivative instruments of our subsidiaries, would have been $87 million at March
Foreign Exchange Rate Risk - We conduct business in various parts of the world
and in various foreign currencies. To limit our foreign currency exchange rate
risk related to operating income, foreign sales agreements generally contain
price provisions designed to insulate our sales revenues against adverse foreign
currency exchange rates. In most countries, energy products are valued and sold
in U.S. dollars and foreign currency operating cost exposures have not been
significant. In other countries, we are paid for product deliveries in local
currencies but at prices indexed to the U.S. dollar. These funds, less amounts
retained for operating costs, are converted to U.S. dollars as soon as
practicable. Our Canadian subsidiaries are paid in Canadian dollars for their
crude oil and natural gas sales and have outstanding Canadian-dollar denominated
debt.
From time to time, we may purchase foreign currency options or enter into
foreign currency swap or foreign currency forward contracts to limit the
exposure related to our foreign currency debt or other obligations. At March 31,
2005, we had various foreign currency forward contracts outstanding related to
operations in Thailand. We evaluated the effect that near term changes in
foreign exchange rates would have had on the fair value of our combined foreign
currency position related to our outstanding foreign currency swaps, forward
contracts and foreign-currency denominated debt. Assuming an adverse change of
ten percent in foreign exchange rates at March 31, 2005, the potential decrease
in fair value of the foreign currency swaps, foreign currency forward contracts
and foreign-currency denominated debt for us would have been $31 million at
Hydrocarbon Derivatives Tables - The following tables set forth the future
volumes and price ranges of hydrocarbon derivatives we held at March 31, 2005,
along with the fair values of those instruments.
2005         2006         2007    Thereafter            (Liability) (b)
Volume (MMBtu)                               430,000            -            -             -                    $ 646
Average price, per MMBtu                      $ 6.50
Volume (MMBtu)                           (23,320,000)           -            -             -                $ (20,881)
Volume (MMBtu)                             8,835,800    9,468,000    7,218,000     7,241,000                $ 141,891
Average swap price, per MMBtu                $ 4.03       $ 3.44       $ 2.47        $ 2.52
Volume (MMBtu)                             9,635,000            -            -             -                $ (17,584)
Average swap price, per MMBtu                 $ 6.22
Average price received, per MMBtu             $ 7.51
Average price paid, per MMBtu                 $ 7.39
Volume (Bbls)                             (5,600,000)           -            -             -                $ (19,426)
Average price, per Bbl                       $ 52.95
==============================================================================================================================
(a)  Futures positions reflect long (short) volumes.
(b)  Net claims against counterparties with non-investment grade credit ratings are immaterial.
2005         2006         2007           (Liability) (b)
Volume (MMBtu)                                   1,100,000            -            -                   $ 2,395
Average price, per MMBtu                            $ 7.11
Volume (MMBtu)                                    (200,000)           -            -                  $ (1,929)
Volume (MMBtu)                                   310,000            -            -                   $ 3,436
Average swap price, per MMBtu                     $ 6.96
Volume (MMBtu)                                   310,000            -            -                  $ (3,395)
Volume (MMBtu)                                  52,570,000    7,225,000            -                  $ (5,415)
Average price paid, per MMBtu                       $ 0.40       $ 0.72          $ -
Volume (MMBtu)                                  53,640,000    7,835,000      900,000                   $ 5,640
Average price received, per MMBtu                   $ 0.40       $ 0.77       $ 1.26
Call Volume -Buy-(MMBtu)                         2,100,000            -            -                     $ (83)
Average Call price                                  $ 7.35
Call Volume -Sell-(MMBtu)                        7,050,000            -            -                    $ (217)
Put Volume -Buy-(MMBtu)                          1,400,000            -            -                     $ (67)
Average Put Price                                   $ 6.77
Put Volume -Sell-(MMBtu)                         2,890,000            -            -                     $ 273
Put Volume (MMBtu)                              1,090,000            -                                  $ (11)
Average Strike price                               $ 0.50
Volume (Bbls)                             8,730,000      175,000            -                  $ 79,252
Average price, per Bbl                     $ 48.67      $ 55.05
Volume (Bbls)                           (8,625,000)    (175,000)           -                 $ (76,862)
Call Volumes -Buy-(Bbls)                         -            -            -                     $ (30)
Average price, per Bbl                         $ -
Call Volumes -Sell-(Bbls)                  400,000            -            -                    $ (472)
Average price, per Bbl                     $ 56.00
Put Volume -Buy-(Bbls)                           -            -            -                    $ (285)
Put Volume -Sell-(Bbls)                          -            -            -                     $ 106
Volume (Bbls)                            6,885,000            -            -                  $ 90,989
Average swap price, per Bbl                $ 37.82
Volume (Bbls)                            6,985,000            -            -                 $ (94,331)
=================================================================================================================
(b)  Includes $10,705 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).
ITEM 4.  CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that
information required to be disclosed in our reports under the Securities
Exchange Act of 1934 is processed, recorded, summarized and reported within the
time periods specified in the SEC's rules and forms and that such information is
accumulated and communicated to our management, including our Chief Executive
Officer and Chief Financial Officer, as appropriate, to allow for timely
decisions regarding required disclosure. In designing and evaluating the
disclosure controls and procedures, management recognizes that any controls and
procedures, no matter how well designed and operated, can provide only
reasonable assurance of achieving the desired control objectives, and management
is required to apply its judgment in evaluating the cost-benefit relationship of
possible controls and procedures.
As required by SEC Rule 13a-15(b), we carried out an evaluation, under the
supervision and with the participation of our management, including our Chief
Executive Officer and our Chief Financial Officer, of the effectiveness of the
design and operation of our disclosure controls and procedures as of the end of
the period covered by this report. Based on the foregoing, our Chief Executive
Officer and Chief Financial Officer concluded, as of that time, that our
disclosure controls and procedures were effective at the reasonable assurance
level.
There was no change in our internal control over financial reporting that
occurred during the three months ended March 31, 2005 that has materially
affected, or is reasonably likely to materially affect, our internal control
over financial reporting. We may make changes in our internal control processes
from time to time in the future.
ITEM 1.   LEGAL PROCEEDINGS.
See the information with respect to certain legal proceedings pending or
threatened against Unocal previously reported in Item 3 of our 2004 10-K. The
following is incorporated by reference: the information regarding the
environmental remediation reserve and possible additional remediation costs in
notes 15 and 16 to the consolidated financial statements in Item 1 of Part I of
this report; the discussion of such amounts in the Environmental Matters section
of Management's Discussion and Analysis in Item 2 of Part I; and the information
regarding certain litigation and claims, tax matters and other contingent
liabilities in note 16 to the consolidated financial statements in Item I of
Part I of this report.
Information with respect to recent development in certain previously reported
proceedings is set forth below:
On March 21, 2005, we announced that Unocal and the plaintiffs finalized
settlement of all lawsuits brought against Unocal by anonymous residents and
former residents of the Tenasserim region of Myanmar. The settlement will
compensate the plaintiffs and provide funds enabling plaintiffs and their
representatives to develop programs to improve living conditions, health care
and education and protect the rights of people from the pipeline region.
ITEM 2.  UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.
In January 2005, we issued 5,346,152 shares of our common stock, together with
cash in lieu of fractional shares, upon conversion of 4,550,645 of the 6-1/4%
convertible preferred securities of Unocal Capital Trust. The shares of common
stock were not registered under the Securities Act of 1933, as amended (the
"1933 Act"), in reliance upon the exemption from registration afforded by
Section 3(a)(9) of the 1933 Act, together with interpretations thereof by the
staff of the Division of Corporation Finance of the SEC, for a security
exchanged by the issuer with its existing security holders, of those of a
subsidiary where no commission or other remuneration is paid or given directly
or indirectly for soliciting such exchange.
The following table shows information regarding repurchases we made of our
shares of common stock during the first quarter of 2005:
Total #     Maximum #
of shares   of Shares
Purchased   That May
as Part of  Yet Be
Total       Avg     Publicly    Purchased
Number of    Price    Announced   Under the
shares     Paid per  Plans or    Plans or
Period        Purchased (1)   share    Programs    Programs
January 1 through January 31, 2005     33,589    $45.49     None
February 1 through February 28, 2005   19,827    $51.21     None
--------------------------------------------------------------------   (2) (3)
March 1 through March 31, 2005         74,742    $60.62     None
Total                               128,158    $55.20     None
1.   During the first quarter, we cancelled 69,507 shares repurchased for the
payment of withholding taxes due on restricted stock that vested under
various employee restricted stock plans.
During the first quarter, we purchased 58,651 shares in the open market and
distributed these shares to employee participants in Unocal's savings
plans, which are defined contribution plans with 401(k) features.
2.   At March 31, 2005, the total authorized common stock repurchase program
limit authorized by our board of directors was $459 million. There is no
expiration date to this repurchase program. No purchases are currently
planned under this program.
3.   In 2004, our board of directors authorized the repurchase from time to time
of shares of our common stock in order to offset the net number of shares
of common stock issued by us upon the exercise or granting, as the case may
be, of existing or subsequently issued stock options or shares of our
restricted common stock. There is no expiration date to the repurchase
program. The board authorized management to determine whether, and when, to
effect any repurchases under this program and did not limit the aggregate
dollar amount for any such repurchases. No purchases are currently planned
under this program.
ITEM 6.  EXHIBITS.
The following exhibits are filed or furnished, as applicable, as part of this
2.1      Agreement and Plan of Merger, dated as of April 4, 2005, among Unocal
Corporation, ChevronTexaco Corporation and Blue Merger Sub Inc.
(incorporated by reference to Exhibit 2.1 to Unocal's Current Report on
Form 8-K dated April 7, 2005, and filed April 7, 2005, File No.
1-8483).
4.1      Amendment No. 4 to Rights Agreement, dated as of April 4, 2005, by and
between Unocal Corporation and Mellon Investor Services LLC
(incorporated by reference to Exhibit 4.2 to Unocal's Form 8-A/A dated
and filed April 7, 2005, File No. 1-8483).
10.1     Employment Agreement, effective February 8, 2005, by and between Unocal
and Samuel H. Gillespie III (incorporated by reference to Exhibit 10.1
to Unocal's Current Report on Form 8-K dated March 31, 2005, and filed
March 31, 2005, File No. 1-8483).
10.2     Form of 2005 Nonqualified Stock Option Award Agreement (incorporated by
reference to Exhibit 10.1 to Unocal's Current Report on Form 8-K dated
February 8, 2005 and filed February 14, 2005, File No. 1-8483).
10.3     Form of 2005 Performance Shares Award Agreement (incorporated by
10.4     Form of 2005 Performance Restricted Stock Award Agreement (incorporated
by reference to Exhibit 10.3 to Unocal's Current Report on Form 8-K
dated February 8, 2005 and filed February 14, 2005, File No. 1-8483).
10.5     Unocal Nonqualified Retirement Plan A1 (incorporated by reference to
Exhibit 10.4 to Unocal's Current Report on Form 8-K dated February 8,
2005, and filed February 14, 2005, File No. 1-8483).
10.6     Unocal Nonqualified Retirement Plan B1 (incorporated by reference to
10.7     Unocal Nonqualified Retirement Plan C1 (incorporated by reference to
10.8     Unocal Nonqualified Savings Plan (incorporated by reference to Exhibit
10.7 to Unocal's Current Report on Form 8-K dated February 8, 2005, and
filed February 14, 2005, File No. 1-8483).
12.1     Statement regarding computation of ratio of earnings to fixed charges
of Unocal Corporation for the three months ended March 31, 2005 and
of Union Oil Company of California for the three months ended March 31,
2005 and 2004.
31.1     Chief Executive Officer certifications pursuant to Exchange Act Rule
13a-14(a).
31.2     Chief Financial Officer certifications pursuant to Exchange Act Rule
32       Furnished Certifications Pursuant to Exchange Act Rule 13a-14(b).
Copies of exhibits will be furnished upon request. Requests should be addressed
to the Corporate Secretary and mailed to the address set forth on the cover page
to this report.
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.
Dated:  May 5, 2005                               By:  /s/JOHN A. BRIFFETT
John A. Briffett
(Duly Authorized Officer and
Principal Accounting Officer)