UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2005
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OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
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Commission file number 1-8483
UNOCAL CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 95-3825062
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2141 ROSECRANS AVENUE, SUITE 4000, EL SEGUNDO, CALIFORNIA 90245
(Address of principal executive offices) (Zip Code)
(310) 726-7600 (Registrant's telephone number,
including area code)
Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
------- -------
Indicate by check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Exchange Act). Yes X No
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Number of shares of common stock, $1.00 par value, outstanding as of
July 29, 2005: 273,631,943
UNOCAL CORPORATION
TABLE OF CONTENTS
PAGE
GLOSSARY i
FORWARD-LOOKING STATEMENTS iii
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
Consolidated Earnings 1
Consolidated Balance Sheets 2
Consolidated Cash Flows 3
Notes to Consolidated Financial Statements 4
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations. 33
Item 3. Quantitative and Qualitative Disclosures About Market Risk. 50
Item 4. Controls and Procedures. 53
PART II. OTHER INFORMATION
Item 1. Legal Proceedings. 54
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds. 54
Item 4. Submission of Matters to a Vote of Security Holders 55
Item 6. Exhibits. 56
SIGNATURE 57
GLOSSARY
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.
-i-
o Lifting is the amount of liquids each working-interest partner takes
physically. The liftings may be more or less than actual entitlements based
on royalties, working interest percentages, and a number of other factors.
o Liquefied Natural Gas ("LNG") is a gas, mainly methane, which has been
liquefied in a refrigeration and pressurization process to facilitate
storage and transportation.
o Liquefied Petroleum Gas ("LPG") is a mixture of butane, propane and other
light hydrocarbons. At normal temperature it is a gas, but when cooled or
subjected to pressure it can be stored and transported as a liquid.
o Multilateral institution refers to an institution with shareholders from
multiple countries that lends money for specific development reasons.
Examples of multilateral institutions are International Finance Corporation
("IFC"), European Bank for Reconstruction and Development ("EBRD"), and
Asian Development Bank ("ADB").
o Natural Gas Liquids ("NGLs") are primarily ethane, propane, butane and
natural gasolines, which can be extracted from wet natural gas and become
liquid under various combinations of increasing pressure and lower
temperature.
o Net acreage and net oil and gas wells are obtained by multiplying gross
acreage and gross oil and gas wells by our working interest percentage in
the properties.
o Net pay is the amount of oil or gas saturated rock capable of producing oil
or gas.
o Net working interest is a working interest after deducting royalties 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.
-ii-
FORWARD-LOOKING STATEMENTS
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
regarding:
o our pending merger with Chevron Corporation ("Chevron"),
o the pending sale of our Canadian exploration and production business to
Pogo Producing Company ("Pogo"),
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 approval by our stockholders of the Chevron merger and the effects on us in
the event that the Chevron merger is not completed,
o satisfaction of the conditions to completing the sale of our Canadian
exploration and production business to Pogo,
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.
iii
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CONSOLIDATED EARNINGS (UNAUDITED) UNOCAL CORPORATION
For the Three Months For the Six Months
Ended June 30, Ended June 30,
-------------------------------------------------------
Millions of dollars except per share amounts 2005 2004 2005 2004
- --------------------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues (a) (see note 3) $ 2,161 $ 1,799 $ 4,200 $ 3,519
Interest, dividends and miscellaneous income 42 19 51 30
Gain on sales of assets (see note 4) 10 40 30 84
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Total revenues 2,213 1,858 4,281 3,633
Costs and other deductions
Crude oil, natural gas and product purchases (a) 748 729 1,478 1,452
Operating expense 323 350 610 609
Administrative and general expense 66 46 144 109
Depreciation, depletion and amortization 269 213 512 416
Impairments 1 9 1 14
Dry hole costs 12 36 31 59
Exploration expense (see note 3) 36 41 66 85
Interest expense (see note 3) 32 46 65 87
Property and other operating taxes 29 22 50 42
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Total costs and other deductions 1,516 1,492 2,957 2,873
Earnings from equity investments 18 38 57 75
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Earnings from continuing operations before
income taxes and minority interests 715 404 1,381 835
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Income taxes 273 138 505 309
Minority interests 2 (1) 4 4
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Earnings from continuing operations 440 267 872 522
Earnings from discontinued operations (b) (see note 6) 35 74 57 88
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Net earnings $ 475 $ 341 $ 929 $ 610
================================================================================================================================
Basic earnings per share of common stock (c)
Continuing operations $ 1.62 $ 1.00 $ 3.22 $ 1.98
Discontinued operations 0.13 0.29 0.21 0.34
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Net earnings $ 1.75 $ 1.29 $ 3.43 $ 2.32
================================================================================================================================
Diluted earnings per share of common stock (d)
Continuing operations $ 1.60 $ 0.98 $ 3.18 $ 1.93
Discontinued operations 0.13 0.27 0.21 0.32
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Net earnings $ 1.73 $ 1.25 $ 3.39 $ 2.25
================================================================================================================================
Cash dividends declared per share of common stock $ 0.20 $ 0.20 $ 0.40 $ 0.40
- --------------------------------------------------------------------------------------------------------------------------------
<FN>
(a) Includes crude oil buy/sell transactions settled in cash of: $ 197 $ 210 $ 360 $ 462
(b) Net of tax (benefit) $ 30 $ 36 $ 48 $ 46
(c) Basic weighted average shares outstanding (in thousands) 271,993 263,916 271,219 262,945
(d) Diluted weighted average shares outstanding (in thousands) 274,811 277,754 274,057 277,232
See Notes to the Consolidated Financial Statements.
</FN>
-1-
CONSOLIDATED BALANCE SHEETS UNOCAL CORPORATION
At June 30, At December 31,
-------------------------------------
Millions of dollars 2005 (a) 2004
- ---------------------------------------------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents (see note 10) $ 1,775 $ 1,160
Accounts and notes receivable - net (see note 3) 1,267 1,423
Inventories (see note 3) 165 220
Deferred income taxes 76 88
Assets held for sale (see note 11) 1,372 -
Other current assets 43 39
- ---------------------------------------------------------------------------------------------------------------
Total current assets 4,698 2,930
Investments and long-term receivables - net (see note 3) 720 777
Properties - net (see note 3) 7,806 8,819
Goodwill 81 136
Deferred income taxes 266 272
Other assets 198 167
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Total assets $ 13,769 $ 13,101
===============================================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ 1,149 $ 1,298
Taxes payable 323 410
Dividends payable 54 53
Interest payable 35 38
Current portion of environmental liabilities (see note 16) 112 109
Current portion of long-term debt and capital leases (see note 14) 464 491
Liabilities of assets held for sale (see note 11) 411 -
Other current liabilities 208 182
- ---------------------------------------------------------------------------------------------------------------
Total current liabilities 2,756 2,581
Long-term debt and capital leases (see note 14) 2,076 2,571
Deferred income taxes 591 839
Accrued abandonment, restoration and environmental liabilities (see note 16) 866 897
Other deferred credits and liabilities 1,093 969
Minority interests 29 27
Commitments and contingencies - (see note 17)
Common stock ($1 par value, shares authorized: 750,000,000 (b)) 289 280
Capital in excess of par value 1,685 1,304
Unearned portion of restricted stock issued (35) (23)
Retained earnings 5,273 4,453
Accumulated other comprehensive income (217) (160)
Notes receivable - key employees (3) (3)
Treasury stock - at cost (c) (634) (634)
- ---------------------------------------------------------------------------------------------------------------
Total stockholders' equity 6,358 5,217
- ---------------------------------------------------------------------------------------------------------------
Total liabilities and stockholders' equity $ 13,769 $ 13,101
===============================================================================================================
<FN>
(a) Unaudited
(b) Number of shares outstanding (in thousands) 272,398 263,190
(c) Number of shares (in thousands) 16,538 16,538
See Notes to the Consolidated Financial Statements.
</FN>
-2-
CONSOLIDATED CASH FLOWS (UNAUDITED) UNOCAL CORPORATION
For the Six Months
Ended June 30,
------------------------------
Millions of dollars 2005 2004
- ---------------------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities
Net earnings $ 929 $ 610
Adjustments to reconcile net earnings to
net cash provided by operating activities
Depreciation, depletion and amortization 567 472
Impairments 1 14
Dry hole costs 32 65
Amortization of exploratory leasehold costs 22 32
Deferred income taxes 119 (6)
Gain on sales of assets (30) (84)
Gain on disposal of discontinued operations (23) (84)
Pension expense net of contributions 47 44
Other (10) (51)
Working capital and other changes related to operations
Accounts and notes receivable 90 45
Inventories 34 (1)
Accounts payable (78) 76
Taxes payable (73) (26)
Other 5 20
- ---------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 1,632 1,126
- ---------------------------------------------------------------------------------------------------------------------
Cash Flows from Investing Activities
Capital expenditures (includes dry hole costs) (873) (801)
Proceeds from sales of assets 117 158
Proceeds from sales of discontinued operations 47 120
Return of capital from affiliate company - 48
- ---------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (709) (475)
- ---------------------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Long-term borrowings 1 135
Reduction of long-term debt and capital lease obligations (291) (241)
Minority interests (3) (1)
Repurchases of common stock - (20)
Proceeds from issuance of common stock 120 94
Dividends paid on common stock (107) (105)
Loans to key employees - 24
Other - (2)
- ---------------------------------------------------------------------------------------------------------------------
Net cash used in financing activities (280) (116)
- ---------------------------------------------------------------------------------------------------------------------
Total increase in cash and cash equivalents 643 535
Less: Cash and cash equivalents of assets held for sale 28 -
Cash and cash equivalents at beginning of year 1,160 404
- ---------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ 1,775 $ 939
=====================================================================================================================
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized) $ 65 $ 87
Income taxes (net of refunds) $ 472 $ 317
See Notes to the Consolidated Financial Statements.
-3-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
1. General
The consolidated financial statements included in this report are unaudited and,
in the opinion of our management, include all adjustments necessary for a fair
statement 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
activities.
Results for the six months ended June 30, 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. We classified as discontinued operations our needle
coke and Western Canada exploration and production businesses and reclassified
all prior periods accordingly. See notes 6, 11 and 21 for further detail.
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 12. Adoption of this rule did
not impact our consolidated earnings in the first six months of 2005. If this
FSP had been applied to 2004, it would not have had a material effect on our
earnings for that year.
-4-
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 $15 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.
SFAS No. 154: In 2005, the FASB issued SFAS No. 154, "Accounting Changes and
Error Corrections - a replacement of APB Opinion No. 20 and SFAS No. 3," which
is effective January 1, 2006. Opinion 20 previously required that most voluntary
changes in accounting principle be recognized by including in net income of the
period of the change the cumulative effect of changing to the new accounting
principle. This Statement requires retrospective application (restatement) to
prior periods' financial statements of changes in accounting principle. This
Statement also applies to changes required by a new accounting pronouncement in
the unusual instance that the pronouncement does not include specific transition
provisions.
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.
-5-
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
$935 million in the second quarter of 2005, compared with $851 million in
the same period a year ago. During the second 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. For the six months ended June 30, 2005 and 2004, sales and
operating revenues from marketing activities were $1.83 billion compared
with $1.68 billion and the percentages attributable to resale activities
were approximately 22 percent and 29 percent, respectively. The percentages
in both the quarterly and yearly periods included crude oil buy/sell
transactions. Crude oil buy/sell amounts were primarily lower in 2005 due
to a significant decrease in 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:
For the Three Months For the Six Months
Ended June 30, Ended June 30,
---------------------- -----------------------
Millions of dollars 2005 2004 2005 2004
- --------------------------------------------------------------------------------
Exploration operations $ 16 $ 18 $ 29 $ 34
Geological and geophysical 12 9 20 24
Amortization of exploratory
leasehold costs 4 11 12 22
Leasehold rentals 4 3 5 5
- --------------------------------------------------------------------------------
Exploration expense $ 36 $ 41 $ 66 $ 85
================================================================================
-6-
The six month period of 2005 compared to the same period a year ago
reflects lower exploration expenditures of $12 million in the United
States, primarily from lower activity in the Gulf of Mexico and $7 million
from International operations.
o Capitalized interest - During the second quarters of 2005 and 2004,
capitalized interest totaled $14 million and $10 million, respectively. For
the six months ended June 30, 2005 and 2004, capitalized interest totaled
$29 million and $26 million, respectively.
o Accounts and notes receivable - The allowance for doubtful accounts and
notes receivable was $4 million and $5 million at June 30, 2005 and
December 31, 2004, respectively.
o Inventories - At June 30, 2005, inventories were $165 million, which was a
decrease of $55 million from year-end 2004 reflecting seasonal natural gas
withdrawals in our Canadian natural gas storage business, which is included
in our Midstream and Marketing segment. The decrease also reflected $5
million which was reclassified to assets held for sale (see note 11).
o Investments and long-term receivables - The allowances for investments and
long-term receivables were $13 million and $32 million at June 30, 2005 and
December 31, 2004, respectively. The decrease in the allowances for the
current year reflects the disposal of our investment interest in two
foreign equity investees.
o Properties - Accumulated depreciation, depletion and amortization was
$12,144 million and $12,597 million at June 30, 2005 and December 31, 2004,
respectively. The current year amount excludes $899 million of accumulated
depreciation, depletion and amortization included in the assets held for
sale amount on the face of the consolidated balance sheet (see note 11).
4. Dispositions Of Assets
Certain of our 2005 asset sales are discussed below:
In April, 2005, we sold our needle coke business for $25 million in cash plus
$22 million in net working capital. We recorded an after-tax gain of $12
million.
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.
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.
We recorded an after-tax gain of $22 million.
5. Income Taxes
Income taxes on earnings from continuing operations for the second quarter and
six month periods of 2005 were $273 million and $505 million, respectively,
compared with $138 million and $309 million for the comparable periods of 2004.
The effective income tax rates for the second quarter and six month periods of
2005 were 38 percent and 37 percent, respectively, compared with 34 percent and
37 percent for the same periods a year ago. The overall higher effective tax
rate in the second quarter of 2005 compared to 2004 is due primarily to a net
deferred benefit of $27 million recorded in the second quarter of 2004 for
settlements and assessments with various taxing authorities. The effective tax
rate for the six months of 2005 included net tax related benefits accrued
related to the sale of Unocal Bharat and other assets along with the tax benefit
effect of currency related adjustments in Thailand. The effective income tax
rate for the six month period of 2004 included the effect of the aforementioned
net deferred tax benefit of $27 million as well as the tax benefit effect in
2004 of currency related adjustments in Thailand.
-7-
6. Discontinued Operations
In May 2005, we announced our intention to sell our Western Canadian exploration
and production assets, and, in July 2005, we entered into an agreement to sell
all of the outstanding capital stock in our wholly owned Canadian subsidiary,
Northrock Resources Ltd. ("Northrock") (see note 21 for further detail). At June
30, 2005, these assets were held for sale (see note 11 for further detail), and
we have classified the results of these operations in discontinued operations on
the consolidated earnings statement. Our Western Canadian exploration and
production assets generated revenues of $123 million and net earnings of $25
million in the second quarter of 2005 compared to revenues of $101 million and
net earnings of $16 million in the second quarter of 2004. These assets
generated revenues of $241 million and net earnings of $42 million in the six
month period of 2005 compared to revenues of $202 million and net earnings of
$28 million in the six month period of 2004.
In April 2005, we sold our needle coke business for $25 million in cash plus net
working capital. We recorded an after-tax gain of approximately $12 million in
the second quarter of 2005. The gain on disposal plus the results of operations
prior to the sale are reported in discontinued operations on the consolidated
earnings statement. The needle coke business generated revenues of $13 million
and a net loss of $2 million in the second quarter of 2005 compared to revenues
of $21 million and a net loss of $1 million in the second quarter of 2004. The
needle coke business generated revenues of $54 million and net earnings of $1
million in the six month period of 2005 compared to revenues of $30 million and
a net loss of $2 million in the six month period of 2004.
In June 2004, we sold certain of our prospective and producing mineral fee lands
in the U.S., which included approximately 2 MBOE/d of production in Mississippi,
Arkansas and Alabama. The producing portion of these mineral fee lands resulted
in an after-tax gain of approximately $43 million. The gain on the asset
disposal plus the results of operations prior to the sale are reported in
discontinued operations on the consolidated earnings statement. These properties
generated revenues of $6 million and net earnings of $3 million in the second
quarter of 2004 and revenues of $12 million and net earnings of $6 million in
the six month period of 2004.
In May 2004, we sold our Cal Ven Pipeline system located in Alberta, Canada and
recorded an after-tax gain of approximately $13 million. The gain on disposal
plus the results of operations prior to the sale are reported in discontinued
operations on the consolidated earnings statement. The Cal Ven pipeline
generated revenues of $1 million and net earnings of less than $1 million in
2004.
The following table summarizes the results from all our discontinued operations
for the periods shown:
For the Fot the
Three Months Six Months
Ended June 30, Ended June 30,
-------------------------------------
Millions of dollars 2005 2004 2005 2004
- -------------------------------------------------------------------------------
Revenues $ 136 $ 128 $ 295 $ 245
Total costs and other deductions 90 102 213 195
- --------------------------------------------------------------------------------
Earnings from discontinued
operations before income taxes 46 26 82 50
Income taxes on discontinued operations 23 8 39 18
- --------------------------------------------------------------------------------
Earnings from discontinued operations 23 18 43 32
Gain on disposal of discontinued
operations before income taxes 19 84 23 84
Income taxes on disposal of
discontinued operations 7 28 9 28
- --------------------------------------------------------------------------------
Gain on disposal of
discontinued operations 12 56 14 56
- --------------------------------------------------------------------------------
Total earnings from
discontinued operations $ 35 $ 74 $ 57 $ 88
================================================================================
-8-
7. Earnings Per Share
The following are reconciliations of the numerators and denominators of the
basic and diluted earnings per share ("EPS") computations for earnings from
continuing operations for the second quarter and six month periods ended June
30, 2005 and 2004:
- ----------------------------------------------------------------------------------------------------------------
Earnings Shares Per Share
Millions of dollars except per share amounts (Numerator) (Denominator) Amount
- ----------------------------------------------------------------------------------------------------------------
Three months ended June 30, 2005
Earnings from continuing operations $ 440 272
Basic EPS $ 1.62
============
Effect of dilutive securities
Options and common stock equivalents 3
------------------------------
Diluted EPS $ 440 275 $ 1.60
============
Three months ended June 30, 2004
Earnings from continuing operations $ 267 264
Basic EPS $ 1.00
============
Effect of dilutive securities
Options and common stock equivalents 2
------------------------------
267 266 $ 1.00
Interest on convertible debentures payable to trust (after-tax) 7 12
------------------------------
Diluted EPS $ 274 278 $ 0.98
============
- ----------------------------------------------------------------------------------------------------------------
Earnings Shares Per Share
Millions except per share amounts (Numerator) (Denominator) Amount
- ----------------------------------------------------------------------------------------------------------------
Six months ended June 30, 2005
Earnings from continuing operations $ 872 271
Basic EPS $ 3.22
============
Effect of dilutive securities
Options and common stock equivalents 3
------------------------------
Diluted EPS $ 872 274 $ 3.18
============
Six months ended June 30, 2004
Earnings from continuing operations $ 522 263
Basic EPS $ 1.98
============
Effect of dilutive securities
Options and common stock equivalents 2
------------------------------
522 265 $ 1.97
Interest on convertible debentures payable to trust (after-tax) 14 12
------------------------------
Diluted EPS $ 536 277 $ 1.93
============
Certain options were not included in the computation of diluted EPS as the
exercise prices were greater than average market prices of the common shares
during the respective periods. The computation of diluted EPS for the three
month and six month periods ended June 30, 2005 included all outstanding common
stock options. For the three month and six month periods ended June 30, 2004,
there were options outstanding to purchase approximately 3.6 million and 2.5
million shares, respectively, of common stock that were excluded from the
computation of diluted EPS.
-9-
8. Comprehensive Income
Unocal's comprehensive income is detailed in the following table:
For the Three Months For the Six Months
Ended June 30, Ended June 30,
----------------------------------------------------
Millions of dollars 2005 2004 2005 2004
- ---------------------------------------------------------------------------------------------------------------------------
Net earnings $ 475 $ 341 $ 929 $ 610
Change in unrealized gain (loss) on hedging instruments (a) 10 (5) (29) (21)
Reclassification adjustment for settled hedging contracts (b) 17 17 (5) 9
Unrealized foreign currency translation adjustments (5) (21) (12) (30)
Minimum pension liability adjustment (c) - - (11) -
- ---------------------------------------------------------------------------------------------------------------------------
Total comprehensive income $ 497 $ 332 $ 872 $ 568
===========================================================================================================================
<FN>
(a) Net of tax effect of: 6 (3) (17) (13)
(b) Net of tax effect of: 10 10 (3) 5
(c) Net of tax effect of: - - (6) -
</FN>
9. 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:
For the Three Months For the Six Months
Ended June 30, Ended June 30,
-------------------------------------------------------
Millions of dollars except per share amounts 2005 2004 2005 2004
- -----------------------------------------------------------------------------------------------------------------------
Net earnings
As reported $ 475 $ 341 $ 929 $ 610
Add: Stock-based employee compensation expense
included in reported net earnings, net of related tax effects
and minority interests 10 2 19 7
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) (2) (19) (9)
-------------------------------------------------------
Pro forma net earnings $ 475 $ 341 $ 929 $ 608
=======================================================
Net earnings per share:
Basic - as reported $ 1.75 $ 1.29 $ 3.43 $ 2.32
Basic - pro forma $ 1.75 $ 1.29 $ 3.43 $ 2.31
Diluted - as reported $ 1.73 $ 1.25 $ 3.39 $ 2.25
Diluted - pro forma $ 1.73 $ 1.25 $ 3.39 $ 2.24
-10-
10. Cash and Cash Equivalents
At June 30, 2005, our cash and cash equivalents had increased by $615 million
from year-end 2004, reflecting the effect of stronger commodity prices during
the first six months of 2005.
At June 30, At December 31,
------------------------------------
Millions of dollars 2005 (a) 2004
- --------------------------------------------------------------------------------
Cash $ 250 $ 243
Time deposits 499 258
Marketable securities 1,026 659
- --------------------------------------------------------------------------------
Cash and cash equivalents $ 1,775 $ 1,160
================================================================================
<FN>
(a) Excludes subsidiary cash of $28 million classified in assets held for sale (see note 11)
</FN>
At June 30, 2005, marketable securities totaled $1.026 billion 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.
11. Assets Held for Sale
At June 30, 2005, we held for sale our exploration and production assets in
Western Canada. On July 8, 2005, we entered into a Share Purchase Agreement with
Pogo to sell all of the outstanding capital stock in our wholly owned Northrock
subsidiary (see note 21 for further detail).
At June 30, 2005, the assets and liabilities of this business were:
Millions of dollars Northrock Resources Ltd.
- --------------------------------------------------------------------------------
Assets held for sale
Cash $ 28
Accounts and notes receivable 53
Inventories 5
Other current assets 1
Investments and long-term receivables - net 2
Properties - net (a) 1,223
Goodwill 54
Other assets 6
- --------------------------------------------------------------------------------
Total $ 1,372
================================================================================
Liabilities held for sale
Accounts payable $ 65
Taxes payable 14
Deferred income taxes 287
Accrued abandonment, restoration and environmental liabilities 38
Other deferred credits and liabilities 7
- --------------------------------------------------------------------------------
Total $ 411
================================================================================
<FN>
(a) net of accumulated depreciation, depletion and amortization of $899 million
</FN>
We have classified the results from operations of these assets as a discontinued
operation (see note 6 for further detail).
-11-
12. Properties and Capital Leases
As of January 1, 2005, we adopted FASB Staff Position FAS 19-1, "Accounting for
Suspended Well Costs." Upon adoption of the FSP, we evaluated all existing
capitalized exploratory well costs under the provisions of the FSP. As a result,
we determined that all these costs met the criteria for capitalization under the
FSP. The following table reflects the net changes in capitalized exploratory
well costs during the first six 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 at June 30, 2004, are presented
based on our previous accounting policy.
For the Six Months
Ended June 30,
----------------------
Millions of dollars 2005 2004
- --------------------------------------------------------------------------------
Beginning balance at January 1 $ 355 $ 364
Additions to capitalized exploratory well costs
pending the determination of proved reserves 19 99
Reclassifications to wells, facilities, and equipment
based on the determination of proved reserves (8) (4)
Capitalized exploratory well costs charged to expense (5) (16)
- --------------------------------------------------------------------------------
Ending balance at June 30 (a) $ 361 $ 443
================================================================================
<FN>
(a) Excludes costs of wells where drilling was
in progress at June 30 of: $ 54 $ 14
</FN>
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:
For the Six Months
Ended June 30,
--------------------
Millions of dollars 2005 2004
- --------------------------------------------------------------------------------
Capitalized exploratory well costs that have been
capitalized for a period of one year or less $ 21 $ 132
Capitalized exploratory well costs that have been
capitalized for a period greater than one year 340 311
---------------------
Balance at June 30 $ 361 $ 443
Number of projects that have exploratory well costs that
have been capitalized for a period greater than one year 11 11
At June 30, 2005, the aging of the $340 million balance of capitalized
exploratory well costs for suspended wells exceeding one year based on the date
drilling was completed consisted of $94 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.
Exploratory well costs that continue to be capitalized for more than one year
after completion of drilling at June 30, 2005, consist of the following: United
States ($125 million for 4 projects); Indonesia ($145 million for 4 projects);
Thailand ($41 million for 1 project); Vietnam ($23 million for 1 project); and
Canada ($6 million for 1 project). An overview of the activities that have been
undertaken to evaluate the major projects and potential reserves and the
information still required to classify the associated reserves as proved appears
in note 11 of our Form 10-Q for the quarterly period ended March 31, 2005.
-12-
13. Postemployment Benefit Plans
We have numerous plans worldwide that provide employees with retirement
benefits. We also have medical plans that provide health care benefits for
eligible employees and many of our retired employees. Most of our plans covering
employees outside of North America are unfunded and resulting liabilities are
extinguished on a "pay as you go" basis.
The components of net periodic benefit cost for our pension and postretirement
medical plans for the three month and six month periods ended June 30, 2005 and
2004 were:
For the Three Months Ended June 30,
Pension Benefits Other Benefits
--------------------- ---------------------
Millions of dollars 2005 2004 2005 2004
- -------------------------------------------------------------------------------------------
Service cost (net of employee contributions) $ 10 $ 8 $ - $ 1
Interest cost 20 20 4 5
Expected return on plan assets (20) (19) - -
Amortization of: - - - -
Prior service cost 2 2 (1) -
Net actuarial losses 15 14 1 2
Curtailment and settlement losses - - - -
- -------------------------------------------------------------------------------------------
Net periodic pension and other benefit costs $ 27 $ 25 $ 4 $ 8
===========================================================================================
For the Six Months Ended June 30,
Pension Benefits Other Benefits
--------------------- ---------------------
Millions of dollars 2005 2004 2005 2004
- -------------------------------------------------------------------------------------------
Service cost (net of employee contributions) $ 20 $ 16 $ 1 $ 2
Interest cost 40 40 8 10
Expected return on plan assets (40) (38) - -
Amortization of: - - - -
Prior service cost 3 3 (3) -
Net actuarial losses 32 30 2 4
Curtailment and settlement losses - - - -
- -------------------------------------------------------------------------------------------
Net periodic pension and other benefit costs $ 55 $ 51 $ 8 $ 16
===========================================================================================
In the second half 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 three month and six
month periods ended June 30, 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:
Pension Benefits Other Benefits
----------------------------------------
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 six months ended June 30, 2005, no contributions were made to the U.S.
Qualified Retirement Plan. Under existing funding regulations, we are not
required to make any cash contributions to our U.S. Qualified Retirement Plan
in 2005.
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
postretirement medical plans in 2005. As of June 30, 2005, we anticipate that
actual contributions to our Supplemental Executive Retirement plans for the full
year 2005 will approximate $70 million while contributions to our foreign
pension and worldwide postretirement medical plans will not vary materially from
the forecasted levels at year-end 2004.
14. Long Term Debt
Unocal's total consolidated debt, including current maturities, was $2.54
billion at June 30, 2005, compared with $3.06 billion at the end of 2004. In
2005, we paid 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 15 for further detail). We retired $85 million in 7.20
percent notes that matured in the first six months of 2005. We paid $77 million
as full payment under the revolving portion of our Canadian dollar-denominated
credit agreement. In addition, we paid $76 million in medium term notes that
matured in the first six months of 2005. Finally, we paid $26 million related to
-13-
a limited recourse loan for our West Seno project in Indonesia and $9 million
related to a non-recourse loan from one of our Geothermal segment subsidiaries.
15. Variable Interest Entities
In January 2005, Unocal Capital Trust (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.
16. Accrued Abandonment, Restoration and Environmental Liabilities
At June 30, 2005, we had accrued $739 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 decrease in the
liability account reflects a reclassification of $38 million as a liability of
assets held for sale (see note 11 for further detail). The account also reflects
an increase in the liability from December 31, 2004 due to $21 million in
accrued pre-tax accretion expense and $10 million in new abandonment liabilities
recorded during the period. These amounts were partially reduced by abandonment
liability settlements totaling $13 million and downward revisions to existing
estimates of $3 million during the first six months of 2005.
Our reserve for environmental remediation obligations at June 30, 2005 totaled
$239 million, of which $112 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:
At June 30, At December 31,
-----------------------------------
Millions of dollars 2005 2004
- --------------------------------------------------------------------------------
Superfund and similar sites $ 12 $ 14
Active Company facilities 25 30
Company facilities sold with retained
liabilities and former Company-operated sites 100 101
Inactive or closed Company facilities 102 99
- --------------------------------------------------------------------------------
Total $ 239 $ 244
================================================================================
17. Commitments and Contingencies
Unocal has contingent liabilities for existing or potential claims, lawsuits and
other proceedings, including those involving environmental, tax, guarantees and
other matters, some of which are discussed more specifically below. We accrue
liabilities when it is probable that future costs will be incurred and these
costs can be reasonably estimated. Accruals are based on developments to date,
our estimates of the outcomes of these matters and our experience in contesting,
litigating and settling other matters. As the scope of the liabilities becomes
better defined, there will be changes in the estimates of future costs, which
could have a material effect on our future results of operations, financial
condition or liquidity.
Environmental matters
We continue to move forward to address environmental issues for which we are
responsible. In cooperation with regulatory agencies and others, we follow
procedures that we have established to identify and cleanup contamination
associated with past operations. We are subject to loss contingencies pursuant
to federal, state, local and foreign environmental laws and regulations. These
include existing and possible future obligations to investigate the effects of
the release or disposal of certain petroleum, chemical and mineral substances at
various sites; to remediate or restore these sites; to compensate others for
damage to property and natural resources, for remediation and restoration costs
and for personal injuries; and to pay civil penalties and, in some cases,
criminal penalties and punitive damages.
-14-
These obligations relate to sites owned by us or owned by others and are
associated with past and present operations, including sites at which we have
been identified as a potentially responsible party ("PRP") under the federal
Superfund laws and comparable state laws.
Liabilities are accrued when it is probable that future costs will be incurred
and such costs can be reasonably estimated. However, in many cases,
investigations are not yet at a stage where we are able to determine whether we
are liable or, even if liability is determined to be probable, to quantify the
liability or estimate a range of possible exposure. In such cases, the amounts
of our liabilities are indeterminate due to the potentially large number of
claimants for any given site or exposure, the unknown magnitude of possible
contamination, the imprecise and conflicting engineering evaluations and
estimates of proper clean up methods and costs, the unknown timing and extent of
the corrective actions that may be required, the uncertainty attendant to the
possible award of punitive damages, the recent judicial recognition of new
causes of action, the present state of the law, which often imposes joint and
several and retroactive liabilities on PRPs, the fact that we are usually just
one of a number of companies identified as a PRP, or other reasons.
Assessment and Remediation
As disclosed in note 16, at June 30, 2005, we had accrued $239 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 $235 million. The amount of such possible additional
costs reflects the aggregate of the high ends of the ranges of costs of feasible
alternatives that we identified for those sites with respect to which
investigation or feasibility studies have advanced to the stage of analyzing
such alternatives. However, such estimated possible additional costs are not an
estimate of the total remediation costs beyond the amounts reserved, because
there are sites where we are not yet in a position to estimate all, or in some
cases any, possible additional costs. Both the amounts reserved and estimates of
possible additional costs will be adjusted, as additional information becomes
available regarding the nature and extent of site contamination, required or
agreed-upon remediation methods and other actions by government agencies and
private parties. Therefore, the amounts reserved and the possible additional
estimated costs may change in the near term, and in some cases could change
substantially.
During the first six months of 2005, cash payments of $48 million were applied
against the reserves and $43 million was added to the reserves. Possible
additional remediation costs increased by $20 million during the first six
months of 2005. The accrued costs and the estimated possible additional costs
are shown below for four categories of sites:
At June 30, 2005
----------------------------
Possible
Millions of dollars Reserve Additional
Costs
- --------------------------------------------------------------------------------
Superfund and similar sites $ 12 $ 15
Active Company facilities 25 35
Company facilities sold with retained liabilities
and former Company-operated sites 100 80
Inactive or closed Company facilities 102 105
- --------------------------------------------------------------------------------
Total $ 239 $ 235
================================================================================
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
-15-
work to be performed, who will perform the work, the timing of the work, who
will pay for the work and other factors that may have an impact on the timing of
the payments for amounts included in the reserve. For some sites, the
remediation work will be performed by other parties, such as the current owners
of the sites, and we have a contractual agreement to pay a share of the
remediation costs. For these sites, we generally have less control over the
timing of the work and consequently the timing of the associated payments. Based
on available information, we estimate that the majority of the amounts included
in the reserve will be paid within the next three to five years.
At the sites where we have contractual agreements to share remediation costs
with third parties, the reserve reflects our estimated shares of those costs. In
many of the oil and gas sites, remediation cost sharing is included in joint
venture agreements that were made with third parties during the original
operation of the sites. In many cases where we sold facilities or a business to
a third party, sharing of remediation costs for those sites may be included in
the sales agreement.
Superfund and similar sites
Contamination at the sites of the "Superfund and similar sites" category was the
result of the disposal of substances at these sites by one or more PRPs.
Contamination of these sites could be from many sources, of which we may be one.
We have been notified that we are a PRP at the sites included in this category.
At the sites where we have not denied liability, our contribution to the
contamination at these sites was primarily from operations in the 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 June 30, 2005, we have received notifications from the EPA that we may be a
PRP at 21 sites and may share certain liabilities at these sites. Of the total,
three sites are under investigation and/or litigation, and our potential
liability is not presently determinable. Of the remaining 18 sites, where we
have concluded that liability is probable and to the extent costs can be
reasonably estimated, a reserve of $8 million has been established for future
remediation and settlement costs.
Various state agencies and private parties have identified 23 other similar PRP
sites. Four 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
costs.
Active Company facilities
The "Active Company facilities" category includes oil and gas fields and mining
operations. The oil and gas sites are primarily contaminated with crude oil, oil
field waste and other petroleum hydrocarbons. Contamination at the active mining
sites was principally the result of the impact of mined material on the
groundwater and/or surface water at these sites. Included in this category are:
o the Molycorp molybdenum mine in Questa, New Mexico
o the Molycorp lanthanide facility in Mountain Pass, California
o Alaska oil and gas properties.
-16-
We have a reserve of $25 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 six months of 2005. During
the first six months of 2005, we made payments of $7 million for this category
of sites.
Company facilities sold with retained liabilities and former Company
operated sites
The "Company facilities sold with retained liabilities and former
Company-operated sites" category includes our former refineries, transportation
and distribution facilities and service stations. The required remediation of
these sites is mainly for petroleum hydrocarbon contamination as the result of
leaking tanks, pipelines or other equipment or impoundments that were used in
these operations. Also included in this category are former oil and gas fields
that we no longer operate. In most cases, these sites are contaminated with
crude oil, oil field waste and other petroleum hydrocarbons. Contamination at
other sites in these categories of sites was the result of former industrial
chemical and polymers manufacturing and distribution facilities and agricultural
chemical retail businesses. Included in this category are:
o West Coast refining, marketing and transportation sites
o auto/truckstop facilities in various locations in the U.S.
o industrial chemical and polymer sites in the South, Midwest
and California
o agricultural chemical sites in the West and Midwest.
In each sale, we retained a contractual remediation or indemnification
obligation and are responsible only for certain environmental 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 $100 million for this group of sites. During the
first six months of 2005, provisions of $25 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 2005
for the remediation of approximately 125 service station, bulk plant and
terminal sites and for the assessment and remediation of oil and gas fields in
Central California. Payments of $26 million were made during the first six
months of 2005 for sites in this category.
Inactive or closed Company facilities
The "Inactive or closed Company facilities" category includes former oil and gas
fields and other locations that are no longer operating. In most cases, these
sites are contaminated with crude oil, oil field waste and other petroleum
hydrocarbons. Other sites in this category were contaminated from former
ferromolybdenum production operations. Included in this category are:
o the Guadalupe oil field on the central California coast
o the Molycorp Washington facility in Pennsylvania
o the Beaumont Refinery in Texas.
A reserve of $102 million has been established for these types of facilities.
During the first six months of 2005, we accrued $15 million related to sites in
this category, primarily for the Guadalupe oil field site. Soil at this site has
been contaminated with diluent, a kerosene-like additive used in the field's
former operations. The provision includes revised estimated costs for
remediation work that is required by the cleanup and abatement order for the
site. The required remediation work has become better defined through ongoing
and continuing meetings and negotiations with the regulatory agencies. This work
includes studies, operation and maintenance of remedial systems, restoration,
and regulatory agency oversight and permitting procedures. Payments of $12
million were made during the first six months of 2005 for sites in this
category.
-17-
Legal Compliance
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 $88 million at June 30, 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
$75 million. Although any possible additional costs for these sites are likely
to be incurred at different times and over a period of many years, we believe
that these obligations could have a material adverse effect on our results of
operations but are not expected to be material to our consolidated financial
condition or liquidity.
Insurance
We maintain insurance coverage intended to reimburse the cost of damages and
remediation related to environmental contamination resulting from sudden and
accidental incidents under current operations. The purchased coverages contain
specified and varying levels of deductibles and payment limits. Although certain
of our contingent legal exposures enumerated above are uninsurable either due to
insurance policy limitations, public policy or market conditions, our management
believes that our current insurance program significantly reduces the
possibility of an incident causing us a material adverse financial impact.
Certain Litigation and Claims
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.
Chevron Merger Litigation: Unocal and its ten directors are defendants in two
putative class action lawsuits challenging the acquisition of Unocal by Chevron.
Initial complaints were brought by individual Unocal stockholders in April 2005
in the Superior Court of California in Los Angeles. The actions were
consolidated and a consolidated complaint was filed on July 14, 2005 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 Chevron over other potential bidders by tailoring the merger agreement
to Chevron 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 Chevron merger agreement.
The consolidated complaint brings a single claim of breach of fiduciary duties.
The lawsuit, Lieb v. Unocal et al., seeks equitable relief by way of an
injunction against the Chevron merger, an order directing Unocal to obtain a
transaction more favorable to Unocal's stockholders, an order to set aside the
merger if consummated and the imposition
-18-
of a constructive trust, as well as unspecified amount of damages to Unocal's
stockholders sustained as a result of the Chevron merger and attorney's fees.
On July 27, 2005, a separate lawsuit was filed in federal court in Los Angeles,
purportedly brought on behalf of a class of Unocal stockholders. The action,
entitled Alaska Electrical Pension Fund v. Unocal Corp., et al., Case No.
CV05-5420 JFW, asserts claims and allegations, and seeks relief, substantially
similar to the consolidated actions filed in California state court, which are
described above. We believe we have substantial meritorious defenses to the
claims.
Unocal and Chevron have reached an agreement in principle with the state court
plaintiffs providing for the settlement of the putative stockholder class action
brought in California state court in connection with the proposed Chevron
merger. In connection with the settlement, it was agreed that Unocal would make
certain disclosures, which are set forth in the Additional Disclosure Relating
to the Proposed Merger with Chevron Corporation filed with the SEC on July 29,
2005. Further, under the terms of settlement, and subject to certain conditions,
all claims relating to the merger agreement and the proposed merger will be
dismissed and released on behalf of the settlement class and the state court
plaintiffs will withdraw their challenges to the proposed merger. The settlement
is subject to California state court approval. Prior to the time at which the
settlement will be submitted to the California state court for final approval,
additional information will be provided to class members in a notice of
settlement.
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 1979-1990 are now closed and barred from additional assessment of federal
income taxes. Although the IRS has completed its audit of Unocal for taxable
years 1991-1994 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 1991-1994 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.
Guarantees Related to Assets or Obligations of Third Parties
Future Remediation Costs
We have agreed to indemnify certain third parties for particular future
remediation costs that may be incurred for properties held by these parties. The
guarantees were established when we either leased property from or sold property
to these third parties. The properties may or may not have been contaminated by
our former operations. Where it has been or will be determined that we are
responsible for contamination, the guarantees require us to pay the costs to
remediate the sites to specified cleanup levels or to levels that will be
determined in the future.
-19-
The maximum potential amount of future payments that we could be required to
make under these guarantees is indeterminate primarily due to the following: the
indefinite term of the majority of these guarantees; the unknown extent of
possible contamination; uncertainties related to the timing of the remediation
work; possible changes in laws governing the remediation process; the unknown
number of claims that may be made; changes in remediation technology; and the
fact that most of these guarantees lack limitations on the maximum potential
amount of future payments.
We have accrued probable and reasonably estimable assessment and remediation
costs for the locations covered under these guarantees. These amounts are
included in the "Company facilities sold with retained liabilities and former
Company-operated sites" category of our reserve for environmental remediation
obligations.
At June 30, 2005, the reserve for this category totaled $100 million. For those
sites where investigations or feasibility studies have advanced to the stage of
analyzing feasible alternative remedies and/or ranges of costs, we estimate that
we could incur possible additional remediation costs aggregating approximately
$80 million.
BTC Construction Completion Guarantee
We have a construction completion guarantee related to debt financing
arrangements for the Baku-Tiblisi-Ceyhan ("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 June 30, 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
$14 million.
In the ordinary course of business, we have agreed to indemnify cash
deficiencies for certain domestic pipeline joint ventures, which we account for
on the equity method. These guarantees are considered in our analysis of overall
risk. 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 June 30, 2005, we had obtained
various surety bonds for $166 million. These surety bonds included a bond for
$58 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 $108 million in various other routine performance bonds held by local, city,
state and federal agencies. We also had obtained $121 million in standby letters
of credit at June 30, 2005, of which $29 million represented letters of credit
with the revenue department in Thailand relating to tax appeals, $41 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.
-20-
Other Guarantees and Credit Rating Triggers
We have various other guarantees for approximately $500 million. Approximately
$118 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 $280 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.,
respectively.
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.
Other Matters
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 $18 million at June 30, 2005. The contract will expire on
September 18, 2005.
We also have other contingent liabilities for litigation, claims and contractual
agreements arising in the ordinary course of business. Based on management's
assessment of the ultimate amount and timing of possible adverse outcomes and
associated costs, none of these other matters is presently expected to have a
material adverse effect on our consolidated financial condition, liquidity or
results of operations.
18. Financial Instruments and Commodity Hedging
Interest rate contracts - We enter into interest rate swap contracts to manage
our debt with the objective of minimizing the volatility and magnitude of our
borrowing costs. We may also enter into interest rate option contracts to
protect our interest rate positions, depending on market conditions. At June 30,
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
months.
Foreign currency contracts - Various foreign exchange currency forward, option
and swap contracts are entered into from time to time to manage our exposures to
adverse impacts of foreign currency fluctuations on recognized obligations and
anticipated transactions. At June 30, 2005, we had no deferred amounts in
accumulated other comprehensive income on the consolidated balance sheet related
to foreign currency contracts.
Commodity hedging activities - We use hydrocarbon derivatives to mitigate our
overall exposure to fluctuations in hydrocarbon commodity prices.
Ineffectiveness for cash flow and fair value hedges was immaterial for the six
months of 2005. At June 30, 2005, we had $9 million of after-tax deferred losses
in accumulated other comprehensive income on the consolidated balance sheet
related to cash flow hedges for future commodity sales for the period beginning
July 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 $2.80 billion at June 30, 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.
-21-
19. Supplemental Condensed Consolidating Financial Information
Unocal guarantees all the publicly held securities issued by its 100
percent-owned subsidiary Union Oil. Such guarantees are full and unconditional
and no subsidiaries of Unocal or Union Oil guarantee these securities. 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 June 30, 2005
Non-
Unocal Union Oil Guarantor
Millions of dollars (Parent) (Parent) Subsidiaries Eliminations Consolidated
- ---------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ 416 $ 2,031 $ (286) $ 2,161
Interest, dividends and miscellaneous income - 7 40 (5) 42
Gain on sales of assets - 2 8 - 10
- ---------------------------------------------------------------------------------------------------------------------
Total revenues - 425 2,079 (291) 2,213
Costs and other deductions
Purchases, operating and other expenses 3 323 1,162 (286) 1,202
Depreciation, depletion and amortization - 79 190 - 269
Impairments - - 1 - 1
Dry hole costs - 10 2 - 12
Interest expense - 28 9 (5) 32
- ---------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 3 440 1,364 (291) 1,516
Equity in earnings of subsidiaries 477 524 - (1,001) -
Earnings from equity investments - (22) 40 - 18
- ---------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 474 487 755 (1,001) 715
- ---------------------------------------------------------------------------------------------------------------------
Income taxes (1) 4 270 - 273
Minority interests - - 2 - 2
- ---------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 475 483 483 (1,001) 440
Earnings from discontinued operations - (6) 41 - 35
- ---------------------------------------------------------------------------------------------------------------------
Net earnings $ 475 $ 477 $ 524 $ (1,001) $ 475
=====================================================================================================================
-22-
CONDENSED CONSOLIDATED EARNINGS STATEMENT
For the Three Months Ended June 30, 2004
Non-
Unocal Union Oil Guarantor
Millions of dollars (Parent) (Parent) Subsidiaries Eliminations Consolidated
- ---------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ 318 $ 1,711 $ (230) $ 1,799
Interest, dividends and miscellaneous income 1 1 19 (2) 19
Gain on sales of assets - (40) 80 - 40
- ---------------------------------------------------------------------------------------------------------------------
Total revenues 1 279 1,810 (232) 1,858
Costs and other deductions
Purchases, operating and other expenses 3 292 1,124 (231) 1,188
Depreciation, depletion and amortization - 65 148 - 213
Impairments - 3 6 - 9
Dry hole costs - 10 26 - 36
Interest expense 9 31 8 (2) 46
- ---------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 12 401 1,312 (233) 1,492
Equity in earnings of subsidiaries 350 443 - (793) -
Earnings from equity investments - 2 37 (1) 38
- ---------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 339 323 535 (793) 404
- ---------------------------------------------------------------------------------------------------------------------
Income taxes (2) (29) 169 - 138
Minority interests - - (1) - (1)
- ---------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 341 352 367 (793) 267
Earnings from discontinued operations - (2) 76 - 74
- ---------------------------------------------------------------------------------------------------------------------
Net earnings $ 341 $ 350 $ 443 $ (793) $ 341
=====================================================================================================================
-23-
CONDENSED CONSOLIDATED EARNINGS STATEMENT
For the Six Months Ended June 30, 2005
Non-
Unocal Union Oil Guarantor
Millions of dollars (Parent) (Parent) Subsidiaries Eliminations Consolidated
- ---------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ 818 $ 3,921 $ (539) $ 4,200
Interest, dividends and miscellaneous income - 14 45 (8) 51
Gain on sales of assets - 2 28 - 30
- ---------------------------------------------------------------------------------------------------------------------
Total revenues - 834 3,994 (547) 4,281
Costs and other deductions
Purchases, operating and other expenses 6 624 2,257 (539) 2,348
Depreciation, depletion and amortization - 147 365 - 512
Impairments - - 1 - 1
Dry hole costs - 11 20 - 31
Interest expense 1 55 17 (8) 65
- ---------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 7 837 2,660 (547) 2,957
Equity in earnings of subsidiaries 934 968 - (1,902) -
Earnings from equity investments - (21) 78 - 57
- ---------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 927 944 1,412 (1,902) 1,381
- ---------------------------------------------------------------------------------------------------------------------
Income taxes (2) 4 503 - 505
Minority interests - - 4 - 4
- ---------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 929 940 905 (1,902) 872
Earnings from discontinued operations - (6) 63 - 57
- ---------------------------------------------------------------------------------------------------------------------
Net earnings $ 929 $ 934 $ 968 $ (1,902) $ 929
=====================================================================================================================
-24-
CONDENSED CONSOLIDATED EARNINGS STATEMENT
For the Six Months Ended June 30, 2004
Non-
Unocal Union Oil Guarantor
Millions of dollars (Parent) (Parent) Subsidiaries Eliminations Consolidated
- ---------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ 644 $ 3,311 $ (436) $ 3,519
Interest, dividends and miscellaneous income 1 5 27 (3) 30
Gain on sales of assets - (16) 100 - 84
- ---------------------------------------------------------------------------------------------------------------------
Total revenues 1 633 3,438 (439) 3,633
Costs and other deductions
Purchases, operating and other expenses 5 521 2,208 (437) 2,297
Depreciation, depletion and amortization - 128 288 - 416
Impairments - 6 8 - 14
Dry hole costs - 27 32 - 59
Interest expense 17 57 16 (3) 87
- ---------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 22 739 2,552 (440) 2,873
Equity in earnings of subsidiaries 628 681 - (1,309) -
Earnings from equity investments - 3 73 (1) 75
- ---------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 607 578 959 (1,309) 835
- ---------------------------------------------------------------------------------------------------------------------
Income taxes (3) (52) 364 - 309
Minority interests - - 4 - 4
- ---------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 610 630 591 (1,309) 522
Earnings from discontinued operations - (2) 90 - 88
- ---------------------------------------------------------------------------------------------------------------------
Net earnings $ 610 $ 628 $ 681 $ (1,309) $ 610
=====================================================================================================================
-25-
CONDENSED CONSOLIDATED BALANCE SHEET
At June 30, 2005
Non-
Unocal Union Oil Guarantor
Millions of dollars (Parent) (Parent) Subsidiaries Eliminations Consolidated
- ----------------------------------------------------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ 1 $ 1,174 $ 600 $ - $ 1,775
Accounts and notes receivable - net 137 190 1,077 (137) 1,267
Inventories - 7 235 (77) 165
Assets held for sale - - 1,372 - 1,372
Other current assets - 88 31 - 119
- ----------------------------------------------------------------------------------------------------------------------
Total current assets 138 1,459 3,315 (214) 4,698
Properties - net - 1,910 5,899 (3) 7,806
Other assets including goodwill 6,969 6,077 945 (12,726) 1,265
- ----------------------------------------------------------------------------------------------------------------------
Total assets $7,107 $ 9,446 $ 10,159 $ (12,943) $ 13,769
======================================================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ - $ 332 $ 954 $ (137) $ 1,149
Current portion of long-term debt - 185 279 - 464
Liabilities of assets held for sale - - 411 - 411
Other current liabilities 54 266 412 - 732
- ----------------------------------------------------------------------------------------------------------------------
Total current liabilities 54 783 2,056 (137) 2,756
Long-term debt and capital leases - 1,464 612 - 2,076
Deferred income taxes - (224) 815 - 591
Accrued abandonment, restoration
and environmental liabilities - 371 495 - 866
Other deferred credits and liabilities - 708 389 (4) 1,093
Minority interests - - 17 12 29
Stockholders' equity 7,053 6,344 5,775 (12,814) 6,358
- ----------------------------------------------------------------------------------------------------------------------
Total liabilities and stockholders' equity $7,107 $ 9,446 $ 10,159 $ (12,943) $ 13,769
======================================================================================================================
-26-
CONDENSED CONSOLIDATED BALANCE SHEET
At December 31, 2004
Non-
Unocal Union Oil Guarantor
Millions of dollars (Parent) (Parent) Subsidiaries Eliminations Consolidated
- ----------------------------------------------------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ - $ 691 $ 469 $ - $ 1,160
Accounts and notes receivable - net 55 239 1,184 (55) 1,423
Inventories - 8 289 (77) 220
Other current assets - 101 26 - 127
- ----------------------------------------------------------------------------------------------------------------------
Total current assets 55 1,039 1,968 (132) 2,930
Properties - net - 1,935 6,887 (3) 8,819
Other assets including goodwill 6,095 5,713 430 (10,886) 1,352
- ----------------------------------------------------------------------------------------------------------------------
Total assets $6,150 $ 8,687 $ 9,285 $ (11,021) $ 13,101
======================================================================================================================
Liabilities and Stockholders' Equity
Current liabilities
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
Long-term debt and capital leases - 1,648 923 - 2,571
Deferred income taxes - (156) 995 - 839
Accrued abandonment, restoration
and environmental liabilities - 373 524 - 897
Other deferred credits and liabilities - 663 309 (3) 969
Minority interests - - 15 12 27
Stockholders' equity 5,854 5,475 4,862 (10,974) 5,217
- ----------------------------------------------------------------------------------------------------------------------
Total liabilities and stockholders' equity $6,150 $ 8,687 $ 9,285 $ (11,021) $ 13,101
======================================================================================================================
-27-
CONDENSED CONSOLIDATED CASH FLOWS
For the Six Months Ended June 30, 2005
Non-
Unocal Union Oil Guarantor
Millions of dollars (Parent) (Parent) Subsidiaries Eliminations Consolidated
- ---------------------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities
Net cash provided by operating activities $ 2 $ 780 $ 850 $ - $ 1,632
Cash Flows from Investing Activities
Capital expenditures and acquisitions
(includes dry hole costs) - (149) (724) - (873)
Proceeds from sales of assets
and discontinued operations - 14 150 - 164
- ---------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities - (135) (574) - (709)
- ---------------------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Change in long-term debt (14) (162) (114) - (290)
Dividends paid on common stock (107) - - - (107)
Proceeds from issuance of common stock 120 - - - 120
Other - - (3) - (3)
- ---------------------------------------------------------------------------------------------------------------------
Net cash used in financing activities (1) (162) (117) - (280)
- ---------------------------------------------------------------------------------------------------------------------
Total increase in cash and cash equivalents 1 483 159 - 643
- ---------------------------------------------------------------------------------------------------------------------
Less: Cash and cash equivalents of assets held for sale - - 28 - 28
- ---------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at beginning of period - 691 469 - 1,160
- ---------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ 1 $ 1,174 $ 600 $ - $ 1,775
=====================================================================================================================
CONDENSED CONSOLIDATED CASH FLOWS
For the Six Months Ended June 30, 2004
Non-
Unocal Union Oil Guarantor
Millions of dollars (Parent) (Parent) Subsidiaries Eliminations Consolidated
- ---------------------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities
Net cash provided by operating activities $ 7 $ 613 $ 506 $ - $ 1,126
Cash Flows from Investing Activities
Capital expenditures and acquisitions
(includes dry hole costs) - (131) (670) - (801)
Proceeds from sales of assets
and discontinued operations - 28 250 - 278
Return of capital from affiliate company - - 48 - 48
- ---------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities - (103) (372) - (475)
- ---------------------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Change in long-term debt - (193) 87 - (106)
Dividends paid on common stock (105) - - - (105)
Proceeds from issuance of common stock 94 - - - 94
Repurchases of common stock (20) - - - (20)
Other 24 (2) (1) - 21
- ---------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities (7) (195) 86 - (116)
- ---------------------------------------------------------------------------------------------------------------------
Increase in cash and cash equivalents - 315 220 - 535
- ---------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at beginning of period 1 45 358 - 404
- ---------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ 1 $ 360 $ 578 $ - $ 939
=====================================================================================================================
-28-
20. 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. On July 8, 2005, we entered into a Share Purchase
Agreement with Pogo to sell all of the outstanding capital stock in our
Northrock subsidiary in Canada. This transaction includes our exploration and
production assets in Western Canada (see note 21 for further detail).
- ----------------------------------------------------------------------------------------------------------
Segment Information Exploration and Production
For the Three Months North America International
Ended June 30, 2005 Total
Millions of dollars U.S. Canada Total N.A. Asia Other Total Intl E&P
- ----------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 303 $ 1 $ 304 $ 546 $ 111 $ 657 $ 961
Other income (loss) (a) - - - (1) 11 10 10
Inter-segment sales & operating revenues 286 - 286 184 - 184 470
- ----------------------------------------------------------------------------------------------------------
Total 589 1 590 729 122 851 1,441
Earnings from equity investments - - - 15 - 15 15
Earnings (loss) from continuing operations 146 - 146 294 53 347 493
Earnings from discontinued operations (net) - 25 25 - - - 25
- ----------------------------------------------------------------------------------------------------------
Net earnings (loss) 146 25 171 294 53 347 518
- ----------------------------------------------------------------------------------------------------------
Assets (at June 30, 2005) 3,323 1,372 4,695 3,758 1,195 4,953 9,648
- ----------------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------------
Midstream Geothermal Corporate and Other Total
and Net Environ-
Marketing Admin & Interest mental &
(b) General Expense Litigation Other(c)
- ----------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 1,108 $ 45 $ - $ - $ - $ 47 $ 2,161
Other income (loss) (a) 28 (1) - 11 - 4 52
Inter-segment sales & operating revenues 46 - - - - (516) -
- ----------------------------------------------------------------------------------------------------------
Total 1,182 44 - 11 - (465) 2,213
Earnings from equity investments (9) - - - - 12 18
Earnings (loss) from continuing operations 20 17 (28) (21) (27) (14) 440
Earnings from discontinued operations (net) - - - - - 10 35
- ----------------------------------------------------------------------------------------------------------
Net earnings (loss) 20 17 (28) (21) (27) (4) 475
- ----------------------------------------------------------------------------------------------------------
Assets (at June 30, 2005) 1,225 487 - - - 2,409 13,769
- ----------------------------------------------------------------------------------------------------------
<FN>
(a) Includes interest, dividends and miscellaneous income, and gain (loss) on sales of assets.
(b) Sales & operating revenues include $197 million of crude oil buy/sell transactions settled in cash.
(c) Includes eliminations and consolidation adjustments.
</FN>
-29-
- ----------------------------------------------------------------------------------------------------------
Segment Information Exploration and Production
For the Three Months North America International
Ended June 30, 2004 Total
Millions of dollars U.S. Canada Total N.A. Asia Other Total Intl E&P
- ----------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 197 $ 1 $ 198 $ 356 $ 79 $ 435 $ 633
Other income (loss) (a) 35 - 35 1 1 2 37
Inter-segment sales & operating revenues 229 - 229 100 - 100 329
- ----------------------------------------------------------------------------------------------------------
Total 461 1 462 457 80 537 999
Earnings from equity investments - - - 12 2 14 14
Earnings (loss) from continuing operations 108 - 108 137 29 166 274
Earnings from discontinued operations (net) 46 16 62 - - - 62
- ----------------------------------------------------------------------------------------------------------
Net earnings (loss) 154 16 170 137 29 166 336
- ----------------------------------------------------------------------------------------------------------
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-
Marketing Admin & Interest mental &
(b) General Expense Litigation Other(c)
- ----------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 969 $ 124 $ - $ - $ - $ 73 $ 1,799
Other income (loss) (a) 3 13 - 4 - 2 59
Inter-segment sales & operating revenues 38 - - - - (367) -
- ----------------------------------------------------------------------------------------------------------
Total 1,010 137 - 4 - (292) 1,858
Earnings from equity investments 12 (2) - - - 14 38
Earnings (loss) from continuing operations 18 57 (21) (33) (11) (17) 267
Earnings from discontinued operations (net) 13 - - - - (1) 74
- ----------------------------------------------------------------------------------------------------------
Net earnings (loss) 31 57 (21) (33) (11) (18) 341
- ----------------------------------------------------------------------------------------------------------
Assets (at December 31, 2004) 1,303 573 - - - 1,874 13,101
- ----------------------------------------------------------------------------------------------------------
<FN>
(a) Includes interest, dividends and miscellaneous income, and gain (loss) on sales of assets.
(b) Sales & operating revenues include $210 million of crude oil buy/sell transactions settled in cash.
(c) Includes eliminations and consolidation adjustments.
</FN>
-30-
- ----------------------------------------------------------------------------------------------------------
Segment Information Exploration and Production
For the Six Months North America International
Ended June 30, 2005 Total
Millions of dollars U.S. Canada Total N.A. Asia Other Total Intl E&P
- ----------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 607 $ 4 $ 611 $ 1,005 $ 209 $ 1,214 $ 1,825
Other income (loss) (a) 4 - 4 (10) 18 8 12
Inter-segment sales & operating revenues 538 - 538 357 - 357 895
- ----------------------------------------------------------------------------------------------------------
Total 1,149 4 1,153 1,352 227 1,579 2,732
Earnings from equity investments - - - 28 - 28 28
Earnings (loss) from continuing operations 300 1 301 545 101 646 947
Earnings from discontinued operations (net) - 42 42 - - - 42
- ----------------------------------------------------------------------------------------------------------
Net earnings (loss) 300 43 343 545 101 646 989
- ----------------------------------------------------------------------------------------------------------
Assets (at June 30, 2005) 3,323 1,372 4,695 3,758 1,195 4,953 9,648
- ----------------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------------
Midstream Geothermal Corporate and Other Total
and Net Environ-
Marketing Admin & Interest mental &
(b) General Expense Litigation Other(c)
- ----------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 2,206 $ 88 $ - $ - $ - $ 81 $ 4,200
Other income (loss) (a) 30 - - 19 - 20 81
Inter-segment sales & operating revenues 87 - - - - (982) -
- ----------------------------------------------------------------------------------------------------------
Total 2,323 88 - 19 - (881) 4,281
Earnings from equity investments 7 - - - - 22 57
Earnings (loss) from continuing operations 55 34 (57) (36) (39) (32) 872
Earnings from discontinued operations (net) - - - - - 15 57
- ----------------------------------------------------------------------------------------------------------
Net earnings (loss) 55 34 (57) (36) (39) (17) 929
- ----------------------------------------------------------------------------------------------------------
Assets (at June 30, 2005) 1,225 487 - - - 2,409 13,769
- ----------------------------------------------------------------------------------------------------------
<FN>
(a) Includes interest, dividends and miscellaneous income, and gain (loss) on sales of assets.
(b) Sales & operating revenues include $360 million of crude oil buy/sell transactions settled in cash.
(c) Includes eliminations and consolidation adjustments.
</FN>
-31-
- ----------------------------------------------------------------------------------------------------------
Segment Information Exploration and Production
For the Six Months North America International
Ended June 30, 2004 Total
Millions of dollars U.S. Canada Total N.A. Asia Other Total Intl E&P
- ----------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 495 $ 3 $ 498 $ 708 $ 136 $ 844 $ 1,342
Other income (loss) (a) 45 - 45 2 2 4 49
Inter-segment sales & operating revenues 435 - 435 202 - 202 637
- ----------------------------------------------------------------------------------------------------------
Total 975 3 978 912 138 1,050 2,028
Earnings from equity investments - - - 22 2 24 24
Earnings (loss) from continuing operations 221 - 221 295 46 341 562
Earnings from discontinued operations (net) 49 28 77 - - - 77
- ----------------------------------------------------------------------------------------------------------
Net earnings (loss) 270 28 298 295 46 341 639
- ----------------------------------------------------------------------------------------------------------
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-
Marketing Admin & Interest mental &
(b) General Expense Litigation Other(c)
- ----------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 1,918 $ 164 $ - $ - $ - $ 95 $ 3,519
Other income (loss) (a) 8 45 - 10 - 2 114
Inter-segment sales & operating revenues 72 - - - - (709) -
- ----------------------------------------------------------------------------------------------------------
Total 1,998 209 - 10 - (612) 3,633
Earnings from equity investments 28 (1) - - - 24 75
Earnings (loss) from continuing operations 41 94 (48) (65) (27) (35) 522
Earnings from discontinued operations (net) 13 - - - - (2) 88
- ----------------------------------------------------------------------------------------------------------
Net earnings (loss) 54 94 (48) (65) (27) (37) 610
- ----------------------------------------------------------------------------------------------------------
Assets (at December 31, 2004) 1,303 573 - - - 1,874 13,101
- ----------------------------------------------------------------------------------------------------------
<FN>
(a) Includes interest, dividends and miscellaneous income, and gain (loss) on sales of assets.
(b) Sales & operating revenues include $462 million of crude oil buy/sell transactions settled in cash.
(c) Includes eliminations and consolidation adjustments.
</FN>
21. Subsequent Event
On July 8, 2005, Unocal and two of its Canadian subsidiaries entered into a
Share Purchase Agreement with Pogo and one of its Canadian subsidiaries. The
agreement provides that Unocal will sell all of the outstanding capital stock in
its Northrock subsidiary in Canada to Pogo for US$1.8 billion in cash. For a
copy of the agreement and additional information regarding the pending sale,
refer to our current report on Form 8-K, filed with the SEC on July 12, 2005.
On July 29, 2005, we repaid our $200 million Canadian dollar-denominated term
loan which was scheduled to mature in November 2009. The amount repaid
translated to $163 million, using the applicable foreign exchange rate.
-32-
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, which is incorporated into this item 2.
RECENT DEVELOPMENTS
Pending Merger with Chevron
On April 4, 2005, we entered into a merger agreement with Chevron Corporation
and Blue Merger Sub Inc., a direct wholly-owned subsidiary of Chevron. The
merger agreement provides that, upon the terms and subject to the conditions set
forth in the merger agreement, Unocal would merge with and into Blue Merger Sub
and the separate corporate existence of Unocal would cease, with Blue Merger Sub
remaining as the surviving corporation in the merger.
On June 22, 2005, Unocal received an unsolicited competing proposal from CNOOC
Limited ("CNOOC"), an affiliate of China National Offshore Oil Company, to
acquire all outstanding shares of Unocal for $67 per share in cash. On June 23,
2005, Chevron granted Unocal a waiver under the Chevron merger agreement
enabling Unocal, at any time prior to the date of the Unocal stockholder vote on
the merger with Chevron, to negotiate with CNOOC and its representatives without
the need for Unocal's board to make certain threshold determinations that
otherwise would be required under the Chevron merger agreement.
On July 1, 2005, we filed with the SEC a final joint proxy statement/prospectus
for the special meeting of Unocal stockholders, scheduled for August 10, 2005,
to vote on the Chevron merger.
On July 19, 2005, following discussions and negotiations with CNOOC with respect
to the CNOOC proposal as well as negotiations with Chevron with respect to the
Chevron transaction, Unocal, Chevron and Blue Merger Sub entered into an
amendment to the Chevron merger agreement. This amendment has the effect of
increasing the merger consideration paid to Unocal stockholders for their
shares. Pursuant to the amended merger agreement, each Unocal stockholder would
have the right to elect to receive, for each Unocal share:
o a combination of 0.618 of a share of Chevron common stock and $27.60 in cash;
o 1.03 shares of Chevron common stock; or
o $69 in cash.
The all-stock and all-cash elections above would be subject to proration to
preserve an overall per share mix of 0.618 of a share of Chevron common stock
and $27.60 in cash for all of the outstanding shares of Unocal common stock
taken together.
On July 25, 2005, we filed with the SEC a supplement to our proxy statement for
the special stockholders meeting to vote on the Chevron merger.
On August 1, 2005, Institutional Shareholder Services recommended that Unocal
stockholders vote for the merger with Chevron.
On August 2, 2005, CNOOC withdrew its bid proposal.
Unocal and Chevron currently expect to complete the merger promptly after Unocal
stockholders approve and adopt the amended merger agreement and the merger at
the special meeting, currently scheduled to be held on August 10, 2005, and
after the satisfaction or waiver of all other conditions to the merger. We
currently expect this to occur shortly after the special meeting. However, there
can be no assurance that the conditions to closing will be met or that the
merger will be completed shortly after the special meeting.
-33-
The foregoing description of the merger and the merger agreement, as amended,
does not purport to be complete and is qualified in its entirety by reference to
the merger agreement, as amended, which has been filed as Exhibit 2.1 to our
Form 8-K filed on April 7, 2005 (original merger agreement) and Exhibit 2.1 to
our Form 8-K filed on July 22, 2005 (amendment no. 1 to the merger agreement).
For additional information regarding the pending merger, refer to Unocal's
current reports on Form 8-K, as amended, filed with the SEC on April 4, April 7,
June 9, June 10, June 23, June 24, June 30, July 6, July 20, July 22, July 29
and August 1, 2005, and any subsequent current or periodic reports that may be
filed by Unocal with the SEC in connection with the pending merger transaction.
Please also refer to the Form S-4 registration statement filed by Chevron and
the proxy statement, as supplemented, that was filed by Unocal, in each case
with the SEC in connection with the pending merger transaction.
Pending Sale of Canadian Exploration and Production Business
On July 8, 2005, we entered into an agreement with Pogo to sell all of the
outstanding capital stock in our wholly owned Northrock subsidiary in Canada for
$1.8 billion in cash. We expect to realize after-tax proceeds from the sale of
approximately $1.5 billion. Northrock represents essentially all of our Canadian
oil and gas reserves and production. Northrock had reserves of 110 million BOE
at year-end 2004, less than 7 percent of our worldwide hydrocarbon reserves, and
average daily net production of 28,100 BOE in the second quarter of 2005. The
Northrock transaction, which is subject to customary Canadian regulatory
approvals, is expected to close in the third quarter of 2005.
OVERVIEW
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.
In addition to developments regarding our pending merger with Chevron, which
have been discussed elsewhere in this report and in our other public
disclosures, some of our more significant operational highlights and other
activities from the first six months of 2005 are listed below:
o began crude oil and natural gas production from the Mad Dog and K-2 fields in
the Gulf of Mexico,
o began production from Phase 2 of the Thailand crude oil project,
o began production 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 line-fill of the BTC crude oil export pipeline from the Caspian Sea to
Turkey,
o began natural gas and condensate production from the Moulavi Bazar field in
Bangladesh,
o encountered hydrocarbons in a secondary objective at the Knotty Head well,
located in Green Canyon Block 512 in the Gulf of Mexico,
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,
o entered into a farm-in agreement for acreage in the Turkey and Georgia
sections of the Eastern Black Sea, and
o completed the redemption of our outstanding 6-1/4% convertible junior
subordinated debentures.
Commodity Prices and Operating Results
Commodity prices remained volatile during the first six months of 2005.
Commodity prices reached all-time highs in June and July of 2005. Our worldwide
production increased by 9 percent in the first six months of 2005 compared to
the first six months of 2004 primarily due to increased production from
Thailand, Indonesia, Bangladesh and Azerbaijan. Rising production costs remain a
challenge as the entire oil services industry attempts to benefit from the
higher commodity price environment through pricing increases.
-34-
The following table summarizes our net daily production and average prices for
our North America and International Exploration and Production business units:
For the Three Months For the Six Months
Ended June 30, Ended June 30,
----------------------------------------
2005 2004 2005 2004
- --------------------------------------------------------------------------------
North America Net Daily Production
Liquids (thousand barrels)
U.S. 61 55 59 55
Canada 14 15 15 16
- --------------------------------------------------------------------------------
Total liquids 75 70 74 71
Natural gas - dry basis
(million cubic feet)
U.S. 442 511 448 512
Canada 83 83 83 83
- --------------------------------------------------------------------------------
Total natural gas 525 594 531 595
North America Average Prices
(excluding hedging activities) (a)
Liquids (per barrel)
U. S. $48.72 $35.91 $46.60 $33.66
Canada $37.67 $29.89 $38.00 $29.17
Average $46.56 $34.58 $44.85 $32.66
Natural gas (per mcf)
U. S. $ 5.91 $ 4.80 $ 5.68 $ 5.20
Canada $ 6.35 $ 5.40 $ 6.02 $ 5.37
Average $ 5.98 $ 4.88 $ 5.74 $ 5.23
- --------------------------------------------------------------------------------
North America Average Prices
(including hedging activities) (a)
Liquids (per barrel)
U. S. $48.04 $30.52 $46.39 $29.64
Canada $37.67 $29.89 $38.00 $29.17
Average $46.02 $30.38 $44.68 $29.54
Natural gas (per mcf)
U. S. $ 5.89 $ 4.53 $ 6.02 $ 5.34
Canada $ 6.35 $ 5.08 $ 6.02 $ 5.06
Average $ 5.97 $ 4.61 $ 6.02 $ 5.30
- --------------------------------------------------------------------------------
<FN>
(a) Excludes gains/losses on derivative positions not accounted for as hedges
and ineffective portions of hedges.
</FN>
-35-
For the Three Months For the Six Months
Ended June 30, Ended June 30,
----------------------------------------
2005 2004 2005 2004
- --------------------------------------------------------------------------------
International Net Daily Production (a)
Liquids (thousand barrels)
Asia 74 61 75 64
Other (b) 28 20 24 20
- --------------------------------------------------------------------------------
Total liquids 102 81 99 84
Natural gas - dry basis
(million cubic feet)
Asia 1,156 891 1,083 885
Other (b) 10 31 10 28
- --------------------------------------------------------------------------------
Total natural gas 1,166 922 1,093 913
International Average Prices (c)
Liquids (per barrel)
Asia $49.77 $34.02 $47.63 $32.66
Other $48.31 $36.01 $47.74 $34.30
Average $49.43 $34.52 $47.66 $33.02
Natural gas (per mcf)
Asia $ 3.38 $ 3.02 $ 3.39 $ 2.99
Other $ 5.45 $ 4.01 $ 5.35 $ 4.17
Average $ 3.40 $ 3.03 $ 3.41 $ 3.01
- --------------------------------------------------------------------------------
Worldwide Net Daily Production (b)
Liquids (thousand barrels) 177 151 173 155
Natural gas - dry basis
(million cubic feet) 1,691 1,516 1,624 1,508
Barrels oil equivalent (thousands) 459 404 444 406
Worldwide Average Prices
(excluding hedging activities)(d)
Liquids (per barrel) $48.18 $34.55 $46.43 $32.86
Natural gas (per mcf) $ 4.20 $ 3.76 $ 4.17 $ 3.89
Worldwide Average Prices
(including hedging activities) (d)
Liquids (per barrel) $47.94 $32.61 $46.35 $31.41
Natural gas (per mcf) $ 4.20 $ 3.65 $ 4.26 $ 3.92
- --------------------------------------------------------------------------------
<FN>
(a) International production is presented utilizing
the economic interest method.
(b) Includes proportional interests in production of equity investees of:
Liquids - 1 - 1
Natural gas - 20 - 17
Barrels oil equivalent - 5 - 4
(c) International did not have any hedging activities.
(d) Excludes gains/losses on derivative positions not accounted for
as hedges and ineffective portions of hedges.
</FN>
-36-
CONSOLIDATED RESULTS
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
and six month periods ended June 30, 2005 and 2004:
For the Three Months For the Six Months
Ended June 30, Ended June 30,
------------------------------------------
Millions of dollars 2005 2004 2005 2004
- --------------------------------------------------------------------------------
Earnings from continuing operations $ 440 $ 267 $ 872 $ 522
Earnings from discontinued operations 35 74 57 88
- --------------------------------------------------------------------------------
Net earnings $ 475 $ 341 $ 929 $ 610
================================================================================
Earnings From Continuing Operations
Second Quarter Results: 2nd quarter earnings in 2005 increased $173 million,
or 65 percent, vs. 2nd quarter 2004 primarily due to the following factors:
Positive Variance Factors
o Higher worldwide commodity prices in the current quarter increased net
earnings by approximately $180 million.
o International production was higher in the current quarter and contributed
about $70 million in higher earnings, primarily from new production in
Bangladesh, increased volumes from the ACG crude oil project in Azerbaijan
and increased volumes from our Indonesia and Thailand operations.
o Lower net interest expense due primarily to lower debt levels increased net
earnings by $12 million.
o Lower exploration costs due primarily to lower exploration drilling
activity in Indonesia and Thailand contributed approximately $20 million in
higher earnings.
o In the prior year quarter, we recorded a provision of $46 million pre-tax
($29 million after-tax) associated with the arbitration ruling regarding
Agrium's Kenai, Alaska nitrogen-based fertilizer plant.
Negative Variance Factors
o Lower United States natural gas production reduced net earnings by about
$20 million in the current quarter due primarily to natural production
declines.
o After-tax environmental and litigation expenses were $28 million in the
second quarter of 2005, compared with $15 million in the same period a
year ago.
o In 2004, our Geothermal segment settled an outstanding eight-year dispute
over operation of the Tiwi and Mak-Ban geothermal steam fields in the
Philippines and recorded an after-tax settlement gain of $46 million.
o In the current quarter of 2005, various tax related adjustments resulted in
a charge to tax expense of approximately $10 million. In the prior year
quarter, we recorded a net tax benefit of $27 million for settlements and
assessments with various taxing authorities.
o In the prior year quarter, our subsidiary, Pure Resources Inc. ("Pure"),
recorded a $22 million after-tax gain from the sale of exploratory mineral
fee lands.
-37-
Six Months Results: earnings in the first six months of 2005 increased $350
million, or 67 percent, vs. the first six months of 2004 primarily due to the
following factors:
Positive Variance Factors
o Higher worldwide commodity prices in 2005 increased net earnings by
approximately $335 million.
o International production was higher in 2005 and contributed about $100
million in higher earnings, primarily from new production in Bangladesh and
increased volumes from the ACG crude oil project and our Indonesia and
Thailand operations.
o Lower net interest expense due primarily to lower debt levels increased net
earnings by $29 million.
o Higher results from our pipeline business along with higher margins from
our North America natural gas storage business increased net earnings by
$13 million.
o Higher results from our minerals business increased net earnings by $17
million.
o In 2004, we recorded a provision of $46 million pre-tax ($29 million
after-tax) associated with the arbitration ruling regarding Agrium's Kenai,
Alaska nitrogen-based fertilizer plant.
Negative Variance Factors
o Lower United States natural gas production reduced net earnings by about
$45 million in 2005 due primarily to natural production declines.
o In 2004, we settled an outstanding eight-year dispute over operation of the
Tiwi and Mak-Ban geothermal steam fields in the Philippines and recorded an
after-tax settlement gain of $46 million.
o In 2005, various tax related adjustments resulted in a charge to tax
expense of approximately $10 million, and in 2004 we recorded a net tax
benefit of $27 million for settlements and assessments with various taxing
authorities.
o Higher employee related expenses reduced net earnings by about $15 million.
o After-tax environmental and litigation expenses were $41 million in 2005,
compared with $38 million in 2004.
o The first six months of 2005 included approximately $32 million in
after-tax gains from asset sales, primarily from the sale of miscellaneous
oil and gas properties compared with the first six months of 2004, which
included approximately $54 million in after-tax gains from asset sales,
primarily from the sale of certain of Pure's exploratory mineral fee lands
in the U.S. and the sale of our rights and interests in the Sarulla
geothermal project on the island of Sumatra, Indonesia.
o The first six months of 2004 included a $15 million gain from a litigation
settlement related to a previous asset sale.
Sales and Operating Revenues From Continuing Operations
Second Quarter Results: 2nd quarter sales and operating revenues in 2005
increased by $362 million, or 20 percent, vs. 2nd quarter 2004 primarily due
to the following factors:
Positive Variance Factors
o Higher average commodity prices from our exploration and production
activities, excluding Canada, increased sales revenues by about $300
million. Our worldwide average realized liquids price was $48.90 per Bbl,
which was an increase of $15.98 per Bbl, or 49 percent, from 2004. Our
average realized liquids price included losses from our hedging activities
of 26 cents and $2.15 per Bbl in 2005 and 2004, respectively. Our worldwide
average realized natural gas price was $4.09 per Mcf in 2005, which was an
increase of 52 cents per Mcf, or 15 percent, from the $3.57 per Mcf,
realized in 2004. Our average worldwide natural gas price was not impacted
by hedging activities in the second quarter of 2005 while the second
quarter of 2004 included losses of 10 cents per Mcf.
o Sales and operating revenues from marketing activities were $935 million in
the second quarter of 2005, compared with $851 million in the same period a
year ago. The increase was primarily due to higher liquids and natural gas
prices partially offset by lower marketing volume activity for both liquids
and natural gas. During the second quarters of 2005 and 2004,
approximately 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 periods included crude
oil buy/sell transactions. Crude oil buy/sell amounts were primarily lower
due to a significant decrease in volumes associated with these
-38-
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
marketing centers with higher volumes of commercial activity and greater
market liquidity.
o Higher International production increased sales revenues by approximately
$125 million primarily due to increased production from the ACG crude oil
project in Azerbaijan and higher Thailand natural gas production compared
to the second quarter of 2004.
o Higher liquids production in the United States increased sales revenues by
approximately $10 million primarily due to production from deepwater fields
in the Gulf of Mexico.
Negative Variance Factors
o In the United States, lower natural gas production reduced sales revenues
by approximately $40 million. Most of the decline in the second quarter of
2005 was due to natural field declines.
o In 2004, our Geothermal segment settled an outstanding eight-year dispute
over operation of the Tiwi and Mak-Ban geothermal steam fields in the
Philippines and recorded $77 million to sales and operating revenues as
part of the pre-tax settlement gain.
Six Months Results: sales and operating revenues in 2005 increased by $681
million, or 19 percent, vs. 2004 primarily due to the following factors:
Positive Variance Factors
o Higher average commodity prices from our exploration and production
activities, excluding Canada, increased sales revenues by approximately
$555 million. Our worldwide average realized liquids price was $47.17 per
Bbl, which was an increase of $15.51 per Bbl, or 49 percent, from 2004. Our
average realized liquids price included losses from our hedging activities
of 8 cents and $1.62 per Bbl in 2005 and 2004, respectively. Our worldwide
average realized natural gas price was $4.17 per Mcf in 2005, which was an
increase of 31 cents per Mcf, or 8 percent, from the $3.86 per Mcf,
realized in 2004. Our average worldwide natural gas price included gains
from our hedging activities of 10 cents and 5 cents per Mcf in 2005 and
2004, respectively.
o Sales and operating revenues from marketing activities were $1.83 billion
in 2005, compared with $1.68 billion in 2004. During the first six months
of 2005 and 2004, approximately 22 percent and 29 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 periods included
crude oil buy/sell transactions. Crude oil buy/sell amounts were primarily
lower due to a significant decrease in volumes associated with these
transactions, which was partially offset by higher crude oil prices.
o Higher International production increased sales revenues by approximately
$200 million primarily due to increased production from the ACG crude oil
project in Azerbaijan and higher Thailand natural gas production compared
to 2004.
o Higher liquids production in the United States increased sales revenues by
approximately $15 million primarily due to production from deepwater fields
in the Gulf of Mexico.
-39-
Negative Variance Factors
o In the United States, lower natural gas production reduced sales revenues
by approximately $75 million. Most of the decline in 2005 was due to
natural field declines.
o In 2004, our Geothermal segment settled an outstanding eight-year dispute
over operation of the Tiwi and Mak-Ban geothermal steam fields in the
Philippines and recorded $77 million to sales and operating revenues as
part of the pre-tax settlement gain.
Income Taxes
Income taxes on earnings from continuing operations for the second quarter and
six month periods of 2005 were $273 million and $505 million, respectively,
compared with $138 million and $309 million for the comparable periods of 2004.
The effective income tax rates for the second quarter and six month periods of
2005 were 38 percent and 37 percent, respectively, compared with 34 percent and
37 percent for the same periods a year ago. The overall higher effective tax
rate in the second quarter of 2005 compared to 2004 is due primarily to a net
deferred tax benefit of $27 million recorded in the second quarter of 2004 for
settlements and assessments with various taxing authorities. The effective tax
rate for the six month period of 2005 included net tax related benefits accrued
related to the sale of Unocal Bharat and other assets along with the tax benefit
effect of currency related adjustments in Thailand. The effective income tax
rate for the six month period of 2004 included the effect of the aforementioned
net deferred tax benefit of $27 million as well as the tax benefit effect in
2004 of currency related adjustments in Thailand.
-40-
Earnings From Discontinued Operations
In May 2005, we announced our intention to sell our Western Canadian exploration
and production assets, and, in July 2005, we entered into an agreement to sell
all of the outstanding capital stock in our wholly owned Northrock subsidiary in
Canada (see note 21 for further detail). At June 30, 2005, these assets were
held for sale (see note 11 for further detail), and we have classified the
results from these operations as a discontinued operation.
In April 2005, we sold our needle coke business for $25 million in cash plus net
working capital. We recorded an after-tax gain of approximately $12 million in
the second quarter of 2005. The gain on disposal plus the results of operations
prior to the sale are reported in discontinued operations on the consolidated
earnings statement.
In June 2004, we sold certain of our prospective and producing mineral fee lands
in the U.S., which included approximately 2 MBOE/d of production in Mississippi,
Arkansas and Alabama. The producing portion of these mineral fee lands resulted
in an after-tax gain of approximately $43 million. The gain on the asset
disposal plus the results of operations prior to the sale are reported in
discontinued operations.
In May 2004, we also sold our Cal Ven Pipeline system located in Alberta, Canada
and recorded an after-tax gain of approximately $13 million. The gain on
disposal plus the results of operations prior to the sale are reported in
discontinued operations.
The following table summarizes the revenues, gain on disposal and total earnings
from each of these discontinued operations:
For the Three Months For the Six Months
Ended June 30, Ended June 30,
-----------------------------------------------------
Millions of dollars 2005 2004 2005 2004
- ---------------------------------------------------------------------------------------------------------------------
Revenues
Exploration and Production - U.S. $ - $ 6 $ - $ 12
- Canada 123 101 241 202
- ---------------------------------------------------------------------------------------------------------------------
Total Exploration and Production $ 123 $ 107 $ 241 $ 214
Midstream and Marketing - Cal Ven Pipeline - - - 1
Corporate & Other - Needle Coke Business 13 21 54 30
- ---------------------------------------------------------------------------------------------------------------------
Total revenues from discontinued operations $ 136 $ 128 $ 295 $ 245
=====================================================================================================================
Gain on disposal of discontinued operations
Exploration and Production - U.S. $ - $ 43 $ - $ 43
Midstream and Marketing - Cal Ven Pipeline - 13 - 13
Corporate & Other - Former Refining and Marketing - - 2 -
Corporate & Other - Needle Coke Business 12 - 12 -
- ---------------------------------------------------------------------------------------------------------------------
Total gain on disposal of discontinued operations $ 12 $ 56 $ 14 $ 56
=====================================================================================================================
Earnings from discontinued operations
Exploration and Production - U.S. $ - $ 46 $ - $ 49
- Canada 25 16 42 28
- ---------------------------------------------------------------------------------------------------------------------
Total Exploration and Production $ 25 $ 62 $ 42 $ 77
Midstream and Marketing - Cal Ven Pipeline - 13 - 13
Corporate & Other - Former Refining and Marketing - - 2 -
Corporate & Other - Needle Coke Business 10 (1) 13 (2)
- ---------------------------------------------------------------------------------------------------------------------
Total earnings from discontinued operations $ 35 $ 74 $ 57 $ 88
=====================================================================================================================
-41-
BUSINESS SEGMENT RESULTS
See note 20 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:
Exploration and Production
North America - Included in this category are our oil and gas operations in the
United States and Canada. Our exploration and production assets in Western
Canada are now included as discontinued operations (see notes 6, 11 and 21 to
the consolidated financial statements in Item 1 of this report).
Second Quarter Results: Earnings from continuing operations totaled $146 million
in the second quarter of 2005 compared to $108 million for the same period a
year ago, which was an increase of $38 million. Higher natural gas and liquids
prices contributed $90 million in higher earnings in the second quarter of 2005
compared with the same quarter a year ago. The positive impact from higher
prices was partially offset by lower natural gas production in the second
quarter of 2005 compared with the same period a year ago, which reduced
after-tax earnings by approximately $20 million. United States natural gas
production averaged 442 MMcf/d down from 511 MMcf/d in 2004. Most of the natural
gas production decline was due to natural field declines primarily in the Gulf
of Mexico. The prior year quarter results included a $22 million after-tax gain
from the sale of certain of Pure's exploratory mineral fee lands in the United
States.
Six Months Results: Earnings from continuing operations totaled $301 million in
the first six months of 2005 compared to $221 million for the same period a year
ago, which was an increase of $80 million. Higher natural gas and liquids prices
contributed $160 million in higher earnings in the first six months of 2005
compared with the same period a year ago. Higher liquids production in the
United States increased after-tax earnings by approximately $10 million
primarily due to production from deepwater fields in the Gulf of Mexico. The
positive impact from higher prices and higher liquids production was partially
offset by lower natural gas production in the first six months of 2005 compared
with the same period a year ago, which reduced after-tax earnings by
approximately $45 million. United States natural gas production averaged 448
MMcf/d down from 512 MMcf/d in 2004. Most of the natural gas production decline
was due to natural field declines primarily in the Gulf of Mexico. The first six
months of 2004 included the $22 million after-tax gain from the sale of certain
of Pure's exploratory mineral fee lands in the United States and a $15 million
gain from a litigation settlement related to a previous asset sale.
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.
Second Quarter Results: Earnings from continuing operations totaled $347 million
in the second quarter of 2005 compared to $166 million in the second quarter of
2004. The increase was primarily due to higher liquids and natural gas prices,
which increased net earnings by approximately $95 million. In addition, higher
production principally from Indonesia, Thailand, Bangladesh and Azerbaijan
contributed approximately $70 million to after-tax earnings. International
liquids production averaged 102 MBbl/d in the current quarter, up from 81 MBbl/d
in the same period a year ago, while natural gas production averaged 1,166
MMcf/d in the second quarter of 2005 up from 922 MMcf/d in the same period a
year ago, which was an increase of 26 percent for both liquids and natural gas.
Exploration costs in the current quarter were approximately $20 million lower
than the second quarter of 2004, primarily due to lower exploration drilling
activity in Indonesia and Thailand.
Six Months Results: Earnings from continuing operations totaled $646 million in
the first six months of 2005 compared to $341 million in the first six months of
2004. The increase was primarily due to higher liquids and natural gas prices,
which increased net earnings by approximately $180 million. In addition, higher
production principally from Indonesia, Thailand, Bangladesh and Azerbaijan
contributed approximately $100 million to after-tax earnings. International
liquids production averaged 99 MBbl/d in the first six months of 2005, up from
84 MBbl/d a year ago, while natural gas production averaged 1,093 MMcf/d up from
913 MMcf/d in the same period a year ago, which was an increase of 18 percent
-42-
and 20 percent, respectively. The first six months of 2005 included after-tax
gains of $25 million from the sale of miscellaneous oil and gas properties. The
first six months of 2005 included foreign exchange related tax benefits and a
lower effective tax rate in Thailand, which contributed approximately $30
million to net earnings. Higher DD&A rates attributable primarily to the West
Seno production in Indonesia negatively impacted net earnings by approximately
$25 million.
Midstream and Marketing
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.
Second Quarter Results: Earnings from continuing operations totaled $20 million
in the current quarter compared to $18 million in the second quarter of 2004.
The current period reflects improved results primarily from our pipeline
businesses which included a gain on the sale of a domestic pipeline.
The segment's sales and operating revenues were $1.15 billion in the current
quarter compared to $1.01 billion in the same quarter a year ago. Included in
these totals were sales from marketing activities totaling $935 million in the
current quarter compared to $851 million in the same quarter a year ago,
representing approximately 43 percent and 47 percent of our total sales and
operating revenues for the second quarters of 2005 and 2004, respectively. Sales
from marketing activities include buy/sell transactions. The majority of the
increase in the segment's sales was primarily due to higher liquids and natural
gas prices partially offset by lower marketing volume activity for both liquids
and natural gas.
Six Months Results: Earnings from continuing operations totaled $55 million in
the first six months of 2005 compared to $41 million in the same period a year
ago. The results for the current year reflect improved results from our pipeline
and natural gas storage businesses.
The segment's sales and operating revenues were $2.29 billion in the first six
months of 2005 compared to $1.99 billion in the same period a year ago. Included
in these totals were sales from marketing activities totaling $1.83 billion in
the current six month period compared to $1.68 billion in the same period a year
ago, representing approximately 44 percent and 48 percent of our total sales and
operating revenues for the 2005 and 2004 periods, respectively. Sales from
marketing activities include buy/sell transactions. The increase in the
segment's sales was due to higher liquids and natural gas prices partially
offset by lower marketing volume activity for both liquids and natural gas. In
addition, the increase in sales and operating revenues reflected higher sales
volumes from our natural gas storage business.
Geothermal
The Geothermal segment includes geothermal steam production for power
generation, with operations in the Philippines and Indonesia. Geothermal
activities also include the operation of geothermal steam-fired power plants in
Indonesia and equity interests in natural gas-fired power plants in Thailand.
Second Quarter Results: Earnings from continuing operations totaled $17 million
in the current quarter compared to $57 million in the same period a year ago.
The prior year quarter results included a $46 million gain from the settlement
of the outstanding contract dispute in our Philippines operations.
-43-
Six Months Results: Earnings from continuing operations totaled $34 million in
the first six months of 2005 compared to $94 million in the same period a year
ago. The 2004 results included the $46 million after-tax gain from the
settlement of the outstanding contract dispute in our Philippines operations and
a $21 million after-tax gain from the sale of our rights and interests in the
Sarulla geothermal project on the island of Sumatra, Indonesia. Our Philippines
results were higher in the current year, which was attributable to the new
contract. In addition, the 2004 results included losses from an equity interest
in a natural gas-fired power plant which we sold in 2005.
Corporate and Other
Corporate and Other includes general corporate overhead, miscellaneous
operations (including real estate, carbon and mineral businesses), other
corporate unallocated costs (including environmental and litigation expenses)
and net interest expense.
Second Quarter Results: The results from continuing operations for the current
quarter were a loss of $90 million compared to a loss of $82 million in the same
period a year ago. Net interest expense for the current quarter was $21 million
compared to $33 million in the same quarter a year ago. After-tax expenses for
environmental and litigation matters for the current quarter were $27 million
compared to $14 million in the same quarter a year ago. The current quarter
reflected $6 million after-tax in higher results from our minerals business due
primarily to higher margins attributable to molybdenum prices. In the second
quarter of 2004, we recorded a provision of $46 million pre-tax ($29 million
after-tax) associated with the arbitration ruling regarding Agrium's Kenai,
Alaska nitrogen-based fertilizer plant, and our obligations to supply natural
gas to the plant. In the current quarter, various tax related adjustments
resulted in a charge to tax expense of approximately $10 million. In 2004, we
recorded a net tax benefit of $27 million for settlements and assessments with
various taxing authorities.
Six Months Results: The results from continuing operations for the first six
months of 2005 were a loss of $164 million compared to a loss of $175 million in
the same period a year ago. Net interest expense for the first six months of
2005 was $36 compared to $65 million in the same period a year ago. After-tax
expenses for environmental and litigation matters for the six months of 2005
were $40 million compared to $35 million after-tax for the same period a year
ago. The current year reflected $17 million after-tax in higher results from our
minerals business due primarily to higher margins attributable to molybdenum
prices. The current year also reflected $15 million in higher employee related
expenses. In the current year, various tax related adjustments resulted in a
charge to tax expense of approximately $10 million. In the six month period of
2004, we recorded the aforementioned provision of $29 million after-tax
associated with the arbitration ruling regarding Agrium's Kenai, Alaska
nitrogen-based fertilizer plant and the net tax benefit of $27 million for
settlements and assessments with various taxing authorities.
LIQUIDITY AND CAPITAL RESOURCES
Overview
Cash and cash equivalents on hand totaled $1.78 billion at June 30, 2005, up
from $1.16 billion at the end of 2004. As previously discussed, we have agreed
in our merger agreement with Chevron, 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 Chevron. 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.
On July 8, 2005, we agreed to sell all of the stock of our Northrock subsidiary
in Canada to Pogo for $1.8 billion in cash. We expect to realize after-tax
proceeds from the sale of approximately $1.5 billion. The sale, which is subject
to customary Canadian regulatory approvals, is expected to close in the third
quarter of 2005.
-44-
On July 29, 2005, we repaid our $200 million Canadian dollar-denominated term
loan which was scheduled to mature in November 2009. The amount repaid
translated to $163 million, using the applicable foreign exchange rate.
Cash Flows from Operating Activities
Cash flows from operating activities were $1.63 billion for the six months ended
June 30, 2005, compared with $1.13 billion 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 $873 million for the first six months of 2005 compared
with $801 million in the same period a year ago. The capital expenditure amounts
included $52 million and $63 million in 2005 and 2004, respectively, from our
Canadian operation currently held for sale. The current period results reflected
$60 million and $25 million in higher expenditures from International and United
States operations, respectively.
In the first six months of 2005, capital expenditures included approximately
$355 million for the development of undeveloped proved oil and gas reserves,
primarily in Thailand and Azerbaijan.
Asset Sales
Pre-tax proceeds from asset sales relating to continuing and discontinued
operations were $164 million for the six month period ended June 30, 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 sold our needle coke business for $25 million in cash
plus $22 million in working capital. We also received pre-tax proceeds of $30
million from the sale of other oil and gas properties, $20 million from the sale
of other miscellaneous assets and $10 million from the sale of real estate
properties.
Pre-tax proceeds from asset sales were $278 million for the six months ended
June 30, 2004. We received net proceeds of $176 million from the sale of certain
of our mineral fee lands in the United States, $60 million from the sale of our
rights and interests in the Sarulla geothermal project in Indonesia and $19
million from the sale of the Cal Ven Pipeline system in Canada. We also received
approximately another $23 million from the sale of various properties, primarily
in the Gulf of Mexico.
Long-term Debt
Unocal's total consolidated debt, including current maturities, was $2.54
billion at June 30, 2005, compared with $3.06 billion at the end of 2004. In the
first six months of 2005, we paid 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 15 for further detail). We retired $85 million
in 7.20 percent notes that matured in the first six months of 2005. We paid $77
million as full payment under the revolving portion of our Canadian
dollar-denominated credit agreement, which we terminated in July 2005. In
addition, we paid $76 million in medium term notes that matured in the first six
months of 2005. Finally, we paid $26 million related to a limited recourse loan
for our West Seno project in Indonesia and $9 million related to a non-recourse
loan from one of our Geothermal segment subsidiaries.
Other Financing Activities
In 2005, we received $120 million from the issuance of 3,555,676 shares of our
common stock related to the exercise of existing stock options. This compared to
$94 million from the issuance of 3,986,394 shares for the six months ended June
30, 2004.
-45-
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 provided 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. We terminated this program effective April 15, 2005.
Environmental Matters
We are committed to operating our business in a manner that is environmentally
responsible. This commitment is fundamental to our core values. As part of this
commitment, we have procedures in place to audit and monitor our environmental
performance. In addition, we have implemented programs to identify and address
environmental risks throughout our company.
Probable costs associated with identified and reasonably estimable environmental
obligations have been accrued in a reserve for such obligations. Accruals are
based on developments to date, our estimates of the outcomes of these matters
and our experience in addressing these matters. As the scope of the liabilities
becomes better defined, there will be changes in the estimates of future costs,
which could have a material effect on our future results of operations,
financial condition or liquidity. At June 30, 2005, our reserves for
environmental remediation obligations totaled $239 million, of which $112
million was included in current liabilities. During the first six months of
2005, cash payments of $48 million were applied against the reserves and $43
million was added to the reserves. We may also incur additional liabilities at
sites where remediation liabilities are probable but future environmental costs
are not presently reasonably estimable because the sites have not been assessed
or the assessments have not advanced to stages where costs are reasonably
estimable. At those sites where investigations or feasibility studies have
advanced to the stage of analyzing feasible alternative remedies and/or ranges
of costs, we estimate that we could incur possible additional remediation costs
aggregating approximately $235 million.
The reserve amounts and estimated possible additional costs are grouped into the
following four categories:
At June 30, 2005
----------------------------
Possible
Millions of dollars Reserve Additional
Costs
- --------------------------------------------------------------------------------
Superfund and similar sites $ 12 $ 15
Active Company facilities 25 35
Company facilities sold with retained liabilities
and former Company-operated sites 100 80
Inactive or closed Company facilities 102 105
- --------------------------------------------------------------------------------
Total $ 239 $ 235
================================================================================
See notes 16 and 17 to the consolidated financial statements in Item 1 of this
report for additional information on environmental related matters.
In the first six months of 2005, we recorded provisions of $25 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 2005 for the remediation of
approximately 125 service station, bulk plant and terminal sites and for the
assessment and remediation of oil and gas fields in Central California.
During the first six months of 2005, we recorded provisions of $15 million for
sites in the "Inactive or closed Company facilities" category, primarily for the
Guadalupe oil field site on the central California coast. Soil at this site has
been contaminated with diluent, a kerosene-like additive used in the field's
former operations. The provision includes revised estimated costs for
remediation work that is required by the cleanup and abatement order for the
site. The required remediation work has become better defined through ongoing
and continuing meetings and negotiations with the
-46-
regulatory agencies. This work includes studies, operation and maintenance of
remedial systems, restoration, and regulatory agency oversight and permitting
procedures.
In the first six 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.
Our estimated possible additional costs for the "Inactive or closed Company
facilities" category of sites increased by $10 million during the first six
months of 2005. The increase was primarily for the Guadalupe oil field site.
Higher estimated costs for remediation work may be incurred for groundwater
monitoring, operation and maintenance of remedial systems, restoration, and
regulatory agency oversight and permitting procedures. These revised estimates
are based on ongoing and continuing meetings and negotiations with the
regulatory agencies.
Litigation and Other Contingencies
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 17 to the interim financial statements
included in Item 1 of Part I of this report.
OPERATIONS OUTLOOK
The following operations outlook is based upon our current expectations and
beliefs. These statements are subject to a number of known and unknown risks and
uncertainties that could cause actual results to differ materially from those
described, including our pending merger with Chevron and 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. To seek to mitigate some of that volatility, we have secured fixed
price "hedges" on portions of our anticipated future natural gas and crude oil
production. From July 2005 through December 2006, we have hedge contracts in
place equivalent to approximately 35 percent of our anticipated U.S. Lower 48
production. The average hedge prices through 2006 are approximately $59.00 for
crude oil and $7.90 for natural gas. In addition, there are also hedges in place
from 2007 through mid-2008 ranging from 10 to 20 percent of anticipated U.S.
Lower 48 production.
In the first six months of 2005, we initiated production from all five 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, the Moulavi Bazar field in Bangladesh, the K-2 field in the
deepwater Gulf of Mexico and Phase 2 of the Thailand crude oil project.
Exploration and Production - North America
United States
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,
began production in May 2005. The estimate of our net production for both
the Mad Dog field and K-2 fields combined is expected to average about 5
MBOE/d to 7 MBOE/d in the third quarter of 2005, rising to an average of 8
MBOE/d to 11 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.
-47-
o Our deepwater Gulf of Mexico exploration and appraisal program continues in
2005. We are currently drilling the Knotty Head well, located in Green
Canyon Block 512. We are also currently participating in drilling a well in
Green Canyon Block 821, a follow-up 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.
Canada
o On July 8, 2005, we entered into a Share Purchase Agreement with Pogo to
sell all of the outstanding capital stock in our wholly owned Northrock
subsidiary in Canada for US$1.8 billion in cash. The transaction, which is
subject to customary Canadian regulatory approvals, is expected to close in
the third quarter 2005.
Exploration and Production - International
Asia
Thailand:
o Start up of the Phase 2 development of the Thailand crude oil project
commenced in June 2005 with production expected to ramp 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 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.
Indonesia:
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
Indonesia in 2005.
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.
Bangladesh:
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 14 MBOE/d to 17 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.
-48-
Other International
Azerbaijan:
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 11 MBOE/d to 13 MBOE/d in the third quarter of 2005 and 14
MBOE/d to 16 MBOE/d in the fourth quarter of 2005. Chirag will continue to
average more than 12 MBOE/d net in the second half 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.
Turkey/Georgia:
o We entered into a farm-in agreement for acreage held by BP in the Turkey
and Georgia sections of the Eastern Black Sea. The geologic setting of the
exploration acreage is similar to the ACG field in Azerbaijan but at deeper
water depths (2100 to 5500 feet). Subject to government approvals, we will
acquire a 25 percent working interest in Turkish Block 3534 and a 10
percent working interest in Georgia Blocks APC-IIA, IIB and III. BP plans
to spud an exploration well on one of the prospects in Turkey in the third
quarter of 2005. We expect our share of capital expenditures for the Black
Sea venture to be approximately $50 million in 2005.
Midstream and Marketing
In parallel with the ACG crude oil project, the BTC crude oil pipeline will
start to line-fill portions of the pipeline through Georgia and Turkey in the
second half 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.
FUTURE ACCOUNTING CHANGES
See note 2 to the consolidated financial statements for information about recent
accounting pronouncements.
-49-
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 $11 million at June 30,
2005. Value at risk related to hydrocarbon derivatives held for non-hedging
purposes was immaterial at June 30, 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 June 30, 2005. Assuming a ten percent decrease in our weighted
average borrowing costs at June 30, 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 $83 million at June
30, 2005.
-50-
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.
From time to time, we may purchase foreign currency options or enter into
foreign currency swap or foreign currency forward contracts to limit the
exposure related to our foreign currency debt or other obligations. At June 30,
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 June 30, 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 $25 million at June
30, 2005.
Hydrocarbon Derivatives Tables - The following tables set forth the future
volumes and price ranges of hydrocarbon derivatives we held at June 30, 2005,
along with the fair values of those instruments.
Open Hydrocarbon Hedging Derivative Instruments (a)
(Thousands of dollars)
Fair Value Asset
2005 2006 2007 Thereafter (Liability) (b)
- ---------------------------------------------------------------------------------------------------------------------------
Natural Gas Futures Positions
Volume (MMBtu) 170,000 - - - $ 158
Average price, per MMBtu $ 6.65
Volume (MMBtu) (8,830,000) - - - $ 1,243
Average price, per MMBtu $ 7.14
- ---------------------------------------------------------------------------------------------------------------------------
Natural Gas Swap Positions
Pay fixed price
Volume (MMBtu) 6,206,900 9,508,000 7,218,000 7,241,000 $ 139,350
Average swap price, per MMBtu $ 4.13 $ 3.46 $ 2.47 $ 2.52
Receive fixed price
Volume (MMBtu) 5,340,000 - - - $ (5,926)
Average swap price, per MMBtu $ 6.29
- ---------------------------------------------------------------------------------------------------------------------------
Natural Gas Basis Swap Positions
Volume (MMBtu) 1,220,000 - - - $ 109
Average price received, per MMBtu $ 6.59
Average price paid, per MMBtu $ 6.44
- ---------------------------------------------------------------------------------------------------------------------------
Crude Oil Futures Positions
Volume (Bbls) 70,000 - - - $ (556)
Average price, per Bbl $ 56.05
Volume (Bbls) (1,648,000) - - - $ (10,438)
Average price, per Bbl $ 52.72
- ---------------------------------------------------------------------------------------------------------------------------
<FN>
(a) Futures positions reflect long (short) volumes.
(b) Net claims against counterparties with non-investment grade credit ratings are immaterial.
</FN>
-51-
Open Hydrocarbon Non-Hedging Derivative Instruments (a)
(Thousands of dollars
Fair Value Asset
2005 2006 2007 (Liability) (b)
- ---------------------------------------------------------------------------------------------------------------------------
Natural Gas Futures Positions
Volume (MMBtu) 1,760,000 - 300,000 $ 212
Average price, per MMBtu $ 7.13 $ 7.77
Volume (MMBtu) (1,560,000) - - $ 46
Average price, per MMBtu $ 7.02
- ---------------------------------------------------------------------------------------------------------------------------
Natural Gas Swap Positions
Pay fixed price
Volume (MMBtu) 2,705,000 - 300,000 $ 520
Average swap price, per MMBtu $ 7.01 $ 7.76
Receive fixed price
Volume (MMBtu) 1,852,500 - 600,000 $ (1,174)
Average swap price, per MMBtu $ 6.90 $ 7.74
- ---------------------------------------------------------------------------------------------------------------------------
Natural Gas Spread Swap Positions
Volume (MMBtu) 24,970,000 7,225,000 - $ (8,854)
Average price paid, per MMBtu $ 0.46 $ 0.72 -
Volume (MMBtu) 25,120,000 7,835,000 900,000 $ 9,074
Average price received, per MMBtu $ 0.46 $ 0.77 $ 1.26
- ---------------------------------------------------------------------------------------------------------------------------
Natural Gas Option (Listed & OTC)
Call Volume -Buy-(MMBtu) 5,500,000 - - $ (549)
Average Call price $ 7.97
Call Volume -Sell-(MMBtu) 7,320,000 - - $ 996
Average Call price $ 7.92
Put Volume -Buy-(MMBtu) 1,480,000 1,860,000 - $ (393)
Average Put Price $ 5.49 4.75
Put Volume -Sell-(MMBtu) 6,280,000 1,860,000 - $ 595
Average Put Price $ 4.71 $ 4.75
- ---------------------------------------------------------------------------------------------------------------------------
Crude Oil Futures Positions
Volume (Bbls) 4,340,000 275,000 - $ 52,706
Average price, per Bbl $ 49.92 $ 53.87
Volume (Bbls) (4,040,000) (275,000) - $(52,261)
Average price, per Bbl $ 49.06 $ 52.09
- ---------------------------------------------------------------------------------------------------------------------------
Crude Oil Option (Listed & OTC)
Call Volumes -Sell-(Bbls) - - - $ 6
Average price, per Bbl
Put Volume -Buy-(Bbls) - - - $ (131)
Average price, per Bbl
Put Volume -Sell-(Bbls) - - - $ 101
Average price, per Bbl
- ---------------------------------------------------------------------------------------------------------------------------
Crude Oil Swap Positions
Pay fixed price
Volume (Bbls) 2,860,000 375,000 - $ 68,042
Average swap price, per Bbl $ 34.33 $ 39.29
Receive fixed price
Volume (Bbls) 3,210,000 475,000 - $(77,290)
Average swap price, per Bbl $ 33.26 $ 37.30
- ---------------------------------------------------------------------------------------------------------------------------
<FN>
(a) Futures positions reflect long (short) volumes.
(b) Net claims against counterparties with non-investment grade credit ratings are immaterial.
(c) Prices quoted from the New York Mercantile Exchange (NYMEX) and Inside FERC Gas Report (IFERC).
</FN>
-52-
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.
Internal Control over Financial Reporting
There was no change in our internal control over financial reporting that
occurred during the three months ended June 30, 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.
-53-
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.
See the information with respect to certain legal proceedings pending or
threatened against Unocal previously reported in Item 3 of our 2004 10-K and in
Item 1 of Part II of our Quarterly Report on Form 10-Q for the quarterly period
ended March 31, 2005. The following is incorporated by reference: the
information regarding the environmental remediation reserve and possible
additional remediation costs in notes 16 and 17 to the consolidated financial
statements in Item 1 of Part I of this report; the discussion of such amounts in
the Environmental Matters section of Management's Discussion and Analysis in
Item 2 of Part I; and the information regarding certain litigation and claims,
tax matters and other contingent liabilities in note 17 to the consolidated
financial statements in Item 1 of Part I of this report.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.
Unocal Purchases of Equity Securities
The following table shows information regarding repurchases we made of our
shares of common stock during the second 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
- --------------------------------------------------------------------------------
April 1 through April 30, 2005 21,950 $58.00 None
- --------------------------------------------------------------------
May 1 through May 31, 2005 10,611 $54.92 None
- -------------------------------------------------------------------- (2) (3)
June 1 through June 30, 2005 18,036 $62.32 None
- --------------------------------------------------------------------
Total 50,597 $58.89 None
- --------------------------------------------------------------------------------
1. During the second quarter, we cancelled 7,951 shares repurchased for the
payment of withholding taxes due on restricted stock that vested under
various employee restricted stock plans.
During the second quarter, we purchased 42,646 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 June 30, 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.
-54-
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
Our 2005 annual meeting of stockholders was held on May 23, 2005. The following
actions were taken by our stockholders at the annual meeting, for which proxies
were solicited pursuant to Regulation 14 under the Securities Exchange Act of
1934:
1. The four nominees proposed by our board of directors were elected as
directors by the following votes for three-year terms expiring at the
2008 annual meeting of stockholders, or until their successors are duly
elected and qualified or their earlier resignation, if applicable:
Name Votes For Votes Withheld
Craig Arnold 235,858,287 7,019,783
James W. Crownover 235,981,853 6,896,217
Donald B. Rice 235,583,875 7,294,195
Mark A. Suwyn 235,879,608 6,998,462
2. A proposal to ratify the appointment of PricewaterhouseCoopers LLP as
Unocal's independent auditors for 2005 was passed by a vote of
238,759,878 for (98.34%) versus 2,456,889 against (1.01%) and 1,571,304
abstentions (0.65%). There were 90,000 broker non-votes.
3. A stockholder proposal requiring that the Chairman of the Board be an
independent director who has not previously served as an executive
officer of Unocal failed to pass, with a vote of 23,550,182 for
(11.29%) versus 182,821,266 against (87.66%) and 2,216,143 abstentions
(1.05%). There were 34,290,479 broker non-votes.
-55-
ITEM 6. EXHIBITS.
The following exhibits are filed or furnished, as applicable, as part of this
report:
2.1 Amendment No. 1 to the Agreement and Plan of Merger, dated as of July
19, 2005, among Unocal Corporation, Chevron Corporation and Blue Merger
Sub Inc. (incorporated by reference to Exhibit 2.1 to Unocal's Current
Report on Form 8-K dated July 19, 2005, and filed July 22, 2005, File
No. 1-8483).
2.2 Waiver Letter from Chevron Corporation, dated June 23, 2005
(incorporated by reference to Exhibit 99.2 to Unocal's Current
Report on Form 8-K dated June 23, 2005, and filed June 24, 2005,
File No. 1-8483).
10.1 Share Purchase Agreement dated July 8, 2005 between Unocal Canada
Limited, Unocal Canada Alberta Hub Limited, Unocal Corporation, Pogo
Canada, ULC and Pogo Producing Company (incorporated by reference to
Exhibit 10.1 to Unocal's Current Report on Form 8-K dated July 12,
2005, and filed July 14, 2005, File No. 1-8483).
10.2 Unocal Deferred Compensation Plan of 2005 (incorporated by reference
to Exhibit 10.1 to Unocal's Current Report on Form 8-K dated
July 14, 2005, and filed July 15, 2005, File No. 1-8483).
10.3 2004 Directors' Deferred Compensation and Restricted Stock Unit Award
Plan (as amended and restated effective as of January 1, 2005)
(incorporated by reference to Exhibit 10.2 to Unocal's Current Report
on Form 8-K dated July 14, 2005, and filed July 15, 2005, File No.
1-8483).
10.4 Unocal Nonqualified Retirement Plan A1 (as amended and restated
effective July 14, 2005) (incorporated by reference to Exhibit 10.3 to
Unocal's Current Report on Form 8-K dated July 14, 2005, and filed July
15, 2005, File No. 1-8483).
10.5 Unocal Nonqualified Retirement Plan B1 (as amended and restated
effective July 14, 2005) (incorporated by reference to Exhibit 10.4 to
Unocal's Current Report on Form 8-K dated July 14, 2005, and filed July
15, 2005, File No. 1-8483).
10.6 Unocal Nonqualified Retirement Plan C1 (as amended and restated
effective July 14, 2005) (incorporated by reference to Exhibit 10.5 to
Unocal's Current Report on Form 8-K dated July 14, 2005, and filed July
15, 2005, File No. 1-8483).
31.1 Chief Executive Officer certifications pursuant to Exchange Act
Rule 13a-14(a).
31.2 Chief Financial Officer certifications pursuant to Exchange Act
Rule 13a-14(a).
32 Furnished Certifications Pursuant to Exchange Act Rule 13a-14(b).
Copies of exhibits will be furnished upon request. Requests should be addressed
to the Corporate Secretary and mailed to the address set forth on the cover page
to this report.
-56-
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
UNOCAL CORPORATION
(Registrant)
Dated: August 4, 2005 By: /s/JOHN A. BRIFFETT
-------------------------------
John A. Briffett
Vice President and Comptroller
(Duly Authorized Officer and
Principal Accounting Officer)
-57-