SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 8-K
Current Report Pursuant
to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Date of report (Date of earliest event reported) January 28, 2003
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UNOCAL CORPORATION
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(Exact name of registrant as specified in its charter)
Delaware
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(State or Other Jurisdiction of Incorporation)
1-8483 95-3825062
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(Commission File Number) (I.R.S. Employer Identification No.)
2141 Rosecrans Avenue, Suite 4000, El Segundo, California 90245
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(Address of Principal Executive Offices) (Zip Code)
(310) 726-7600
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(Registrant's Telephone Number, Including Area Code)
Item 5. Other Events.
Fourth Quarter 2002 and Year-To-Date Results
--------------------------------------------
Unocal Corporation's preliminary net earnings were $96 million, or 38 cents
per share (diluted), in the fourth quarter of 2002 compared with a loss of
$29 million, or 12 cents per share (diluted), in the fourth quarter of
2001. For the full year of 2002, preliminary unaudited net earnings were
$331 million, or $1.34 per share (diluted), compared with $615 million,
or $2.50 per share (diluted) in 2001.
For the Three Months For the Twelve Months
Ended December 31, Ended December 31,
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Millions of dollars 2002 2001 2002 2001
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Earnings(loss) from continuing operations $ 96 $ (30) $ 330 $ 599
Earnings from discontinued operations - 1 1 17
Cumulative effect of accounting change - - - (1)
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Net earnings (loss) $ 96 $ (29) $ 331 $ 615
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Continuing Operations
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Fourth Quarter Results: Earnings from continuing operations were $126 million
higher in 2002 compared to the fourth quarter of 2001, primarily reflecting
improved results from the Company's exploration and production operations, due
to higher worldwide commodity prices, lower exploration expenses and higher
International gas production. In the fourth quarter of 2002, the Company's
worldwide average liquids price was $25.28 per barrel, which was an increase of
$6.51 per barrel, or 35 percent, from the same period a year ago. The Company's
hedging program lowered the average realized liquids price by one cent in the
fourth quarter of 2002 while the corresponding period in 2001 included a gain of
15 cents per barrel from hedging activities. The Company's worldwide average
realized natural gas price, including a loss of 2 cents per Mcf from hedging
activities, was $3.02 per Mcf for the fourth quarter of 2002. This was an
increase of 60 cents per Mcf, or 25 percent, from the $2.42 per Mcf, including a
benefit of 10 cents per Mcf from hedging activities, realized during the fourth
quarter of 2001. Higher worldwide commodity prices increased net earnings by
approximately $100 million. Lower worldwide exploration expenses, including dry
hole costs, positively impacted net earnings by approximately $10 million in
2002. International gas production was 919 MMcf/d in the fourth quarter of 2002
compared to 851 MMcf/d in the fourth quarter of 2001, which added approximately
$7 million to net earnings. The fourth quarter of 2001 was negatively impacted
by an $86 million non-cash after-tax charge for impairment of certain Gulf of
Mexico shelf properties due to depressed commodity prices. Net earnings were
also impacted by improved margins from oil and gas marketing activities in 2002,
which increased net earnings by $7 million from the fourth quarter of 2001.
These positive factors were partially offset by lower North America production
volumes, which decreased net earnings by approximately $30 million. North
America production averaged 223,000 barrels-of-oil equivalent ("BOE") per day in
the fourth quarter, down from 279,000 BOE per day a year ago. Approximately 60
percent of the production decline reflected lower production from the Muni field
in the Gulf of Mexico, which had reached peak production rates in the third
quarter of 2001, and hurricane-related production curtailments in the Gulf of
Mexico. Natural declines in older existing fields were responsible for the
remaining portion of the production decline. The fourth quarter of 2002 also
included $9 million after-tax for uninsured losses due to hurricane damage in
the Gulf of Mexico and $8 million after-tax in costs related to the acquisition
of the outstanding minority interest in Pure Resources, Inc., common stock. In
addition, the fourth quarter of 2002 included an after-tax loss of $1 million in
mark-to-market accruals and realized gains/losses for non-hedge commodity
derivatives recorded by the Company's Northrock Resources Ltd. ("Northrock")
subsidiary, compared with an after-tax gain of $5 million in the same period a
year ago. Pension-related costs were $7 million after-tax higher in the fourth
quarter of 2002 compared to the same period a year ago. The fourth quarter of
2001 benefited from $18 million in after-tax earnings related to participation
agreements covering the Company's former agricultural products business and the
Company's former oil and gas operations in California while the after-tax
earnings impact in the current period was $10 million.
-1-
Impairments of certain Alaska properties and a restructuring charge reduced the
Company's Alaska exploration and production after-tax earnings by about $7
million in the current quarter. Higher cash expenses and lower sales revenues
reduced after-tax earnings from the Company's real estate operations by $5
million during the current quarter, compared to the same period a year ago.
After-tax environmental and litigation expenses were $30 million
in the fourth quarter of 2002, compared with $28 million in the same period a
year ago. The fourth quarter of 2002 results included $25 million in net
after-tax gains from asset sales while the fourth quarter of 2001 included $15
million in after-tax gains from asset sales.
Full-Year Results: Earnings from continuing operations were $330 million, or
$1.34 per share (diluted), in 2002, compared with $599 million, or $2.43 per
share (diluted), a year ago. The decrease was primarily due to lower North
America production and natural gas prices. Lower production in North America
reduced net earnings by approximately $175 million from 2001. Natural gas
production averaged 886 MMcf/d in 2002, compared with 1,109 MMcf/d in 2001. The
lower production was principally in the Lower 48 operations, which reflected
lower Gulf of Mexico natural gas production stemming from the decline in Muni
field production (10 MMcf/d, net of royalty, in 2002 versus 105 MMcf/d, net of
royalty, in 2001), the natural declines in existing fields and hurricane-related
production curtailments in the Gulf of Mexico. The lower production in North
America was partially offset by higher production from International operations,
which contributed approximately $25 million in higher 2002 after-tax earnings.
Lower North America natural gas prices reduced net earnings by approximately
$160 million in 2002. The Company's North America average natural gas price,
including a benefit of 5 cents per Mcf from hedging activities, was $2.88 per
Mcf for 2002, which was a decrease of 97 cents per Mcf, or 25 percent, from the
$3.85 per Mcf, including a loss of 4 cents per Mcf from hedging activities in
2001.
The full-year results in 2002 included $25 million after-tax in higher pension
related costs, a $15 million after-tax charge for impairments in Alaska, a $12
million after-tax restructuring provision for the Gulf Region business unit, the
$9 million for uninsured losses due to hurricane damage in the Gulf of Mexico
and the $8 million in costs related to the acquisition of the outstanding
minority interest in Pure Resources, Inc., common stock. The full-year of 2002
included an after-tax loss of $6 million in mark-to-market accruals and realized
gains/losses for non-hedge commodity derivatives by the Company's Northrock
subsidiary, compared with an after-tax gain of $10 million in 2001. In 2001, net
earnings benefited from the $18 million related to participation agreements
covering the Company's former agricultural products business and former oil and
gas operations in California while the earnings impact in 2002 was $10 million.
These negative factors in 2002 were partially offset by lower dry hole costs
compared with the same period a year ago, which increased net earnings by
approximately $40 million. The 2001 results also included an $86 million
non-cash after-tax charge for impairment of certain Gulf of Mexico shelf
properties. In addition, after-tax environmental and litigation expenses
were $92 million in 2002, compared with $108 million in 2001. The 2002
results also included a $2 million after-tax gain from an insurance settlement
reached with insurers for the recovery of amounts previously paid out for
environmental pollution claims. The 2002 results included $26 million in net
after-tax gains from asset sales while 2001 included $13 million in after-tax
gains from asset sales.
Discontinued Operations
-----------------------
In 2002, preliminary unaudited net earnings included a $1 million after-tax gain
from discontinued operations, related to a participation payment received from
the purchaser of the Company's former West Coast refining, marketing and
transportation assets covering price differences between California Air
Resources Board Phase 2 gasoline and conventional gasoline. The equivalent
after-tax gain in 2001 was $17 million.
Cumulative Effect of Accounting Change
--------------------------------------
In the first quarter of 2001, the Company recorded a one-time non-cash $1
million after-tax charge consisting of the cumulative effect of a change in
accounting principle related to the initial adoption of Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities".
-2-
Revenues
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Revenues from continuing operations for the fourth quarter of 2002 were $1.57
billion compared with $1.26 billion for the same period a year ago. The increase
primarily reflected higher commodity prices, partially offset by lower domestic
natural gas production. For the full-year of 2002, total revenues from
continuing operations were $5.25 billion, compared with $6.75 billion for the
full-year of 2001. The decrease primarily reflected lower average hydrocarbon
commodity prices, lower domestic natural gas production and reduced marketing
activity related to the Company's domestic equity crude production.
Financial Condition
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Cash flows from operating activities, including discontinued operations and
working capital and other changes, were $1.57 billion in 2002 compared to $2.13
billion in 2001. This decrease principally reflected the effects of lower North
America natural gas production volumes and lower worldwide commodity prices.
Capital expenditures were $1.67 billion for 2002 compared with $1.73 billion a
year ago. In addition, the Company also spent $646 million for major
acquisitions in 2001.
The Company's total consolidated debt, including current maturities, at the end
of December 2002, was $3.0 billion, compared with $2.91 billion at the end of
2001.
Stockholders' equity was $3.3 billion at year-end 2002, compared with $3.12
billion at December 31, 2001. The net increase of $174 million includes a $391
million increase that reflected the value of the 13.2 million shares of Unocal
common stock issued to acquire the outstanding common stock of Pure Resources,
Inc. that the company did not already own. This increase was offset largely by
an after-tax charge of $334 million to the other comprehensive income component
of equity to recognize the minimum pension liability for the company's qualified
retirement plan. This reflected the excess of the accumulated benefit obligation
for vested current and former employees over the fair value of plan assets at
December 31, 2002. The company was not required to make any cash contribution to
the plan in 2002.
First Quarter 2003 and Full-Year 2003 Outlook
---------------------------------------------
The Company's current net worldwide daily production estimate for the first
quarter of 2003 is between 455,000 and 465,000 BOE. For the first quarter of
2003, the Company assumes average NYMEX benchmark prices of $33.00 per barrel of
crude oil and $5.25 per MMBtu for North America natural gas. The Company's net
earnings for the first quarter are expected to change 4 cents per share for
every $1 change in the Company's average worldwide realized price for crude oil
and 2 cents per share for every 10-cent change in its average realized North
America natural gas price, excluding the effect of hedging activities. For the
first quarter 2003, the Company has hedged 32 billion Btu of Lower 48 natural
gas production with pricing collars between $4.06 and $4.99 per MMBtu, and 1.9
million barrels of Lower 48 crude oil with collars between $28.61 and $31.85 per
barrel. First quarter hedged volumes represent approximately 57 percent and 42
percent of expected Lower 48 natural gas and crude oil production volumes,
respectively. The Company also forecasts first quarter pre-tax dry hole costs of
$50 to $60 million.
For the full-year 2003, the Company assumes average NYMEX benchmark prices of
$30.00 per barrel of crude oil and $5.00 per MMBtu for North America natural gas
production. For the full-year 2003, the Company has hedged 70.6 billion Btus of
Lower 48 natural gas production with collars of $3.92 to $4.81 per MMBtu. This
volume represents approximately 27 percent of expected Lower 48 natural gas
production. Hedged crude oil production volumes beyond the first quarter are
immaterial. The Company's net earnings for the full-year are expected to change
14 cents per share for each $1 change in the Company's average worldwide
realized price for crude oil and 7 cents per share for every 10-cent change in
its average realized North America natural gas price, excluding the effect of
hedging activities. The Company forecasts pretax dry hole costs of $115 to $145
million and that pretax pension-related expenses will increase over 2002 by
approximately $50 million. The Company currently estimates its full-year 2003
production to be at the lower end of the previously disclosed range of 480,000
to 495,000 BOE per day. The expected production increase from the 2002 levels
primarily reflects the anticipated start of new oil production from the West
Seno field in Indonesia in the second quarter of 2003.
-3-
The Company's total actual production for the year could be impacted by cost
recovery volume reductions under the Company's various foreign Production
Sharing Contracts ("PSCs") due to higher oil prices, demand for gas in Thailand,
production and exploration performance in the Gulf of Mexico, and possible asset
sales of marginal producing properties from North America operations. Depletion
and depreciation expense for the full-year 2003 is expected to increase by
$35-$45 million pre-tax, primarily due to the production mix effect of new
fields and higher expected future abandonment costs. The Company currently
forecasts that after-tax interest expense for the full-year 2003 will be between
$140 and $150 million.
Capital expenditures for 2003 are currently forecast at approximately $1.7
billion, essentially unchanged from 2002. Capital spending on major developments
will continue to account for an increasing larger percentage of the Company's
overall capital spending program in 2003 with expenditures focused at West Seno
(Deepwater Offshore East Kalimantan in Indonesia), Phase I AIOC (Caspian Sea
Offshore Azerbaijan) and the Mad Dog (Deepwater Gulf of Mexico) development
projects. Exploration capital expenditures in 2003 are currently expected to
approach 2002 levels with exploratory drilling programs targeting deepwater
prospects in Indonesia and the Gulf of Mexico and Deep Shelf prospects offshore
Louisiana and Texas.
Common share equivalents for purposes of computing fully diluted earnings are
forecasted to average 260 million shares for both the first quarter and
full-year.
2002 Reserve Replacement and FD&A Results
-----------------------------------------
The Company estimates its preliminary year-end 2002 proved oil and gas reserves
to be 1.77 billion BOE, compared with 1.82 billion BOE at the end of 2001. The
year-end estimates reflect additions of 140 million BOE from discoveries and
extensions and a net 88 million BOE from performance-related revisions and
improved recovery. These were offset partially by a net reduction of 84 million
BOE in price-related revisions. The price-related revisions included 28 million
BOE in upward revisions, primarily in onshore U.S. fields, which were offset by
112 million BOE of negative revisions in fields covered by the Company's various
International PSCs.
Including the net effect of price revisions, preliminary reserve replacement was
75 percent of 2002 production, with a finding and development ("F&D") cost of
$11.63 per BOE and a finding, development and acquisition ("FD&A") cost of
$12.43 per BOE. Excluding the impact of all price-related revisions, reserve
replacement would have been 123 percent, with an F&D cost of $7.34 per BOE and
an FD&A cost of $7.99 per BOE. Excluding the effect of PSC price-related
revisions alone, the Company's reserve replacement would have been 139 percent,
with an F&D cost of $6.54 per BOE and an FD&A cost of $7.14 per BOE.
Under foreign PSC arrangements in Indonesia, Myanmar, Azerbaijan ("AIOC"),
Bangladesh, and the Democratic Republic of the Congo, net entitlement reserves
to the Company increase as oil and/or gas prices decline and decrease when they
rise. Benchmark crude oil prices rose from $19.71 per barrel at year-end 2001 to
$31.23 per barrel at the end of 2002. Comparable price increases in
International operations resulted in the 112 million BOE negative revisions in
the Company's reserves under its PSCs because fewer equivalent barrels were
required at the year-end price levels to reimburse the company for its costs.
-4-
Additional Interests in Indonesia Production Sharing Contracts
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The Company's Unocal Donggala Limited ("Unocal Donggala") subsidiary reached
agreement to farm in to the deepwater Donggala PSC area offshore East
Kalimantan, Indonesia. Unocal Donggala will acquire a 19.55 percent
non-operating working interest in the PSC. The Donggala PSC area lies outboard
of the Rapak PSC area, where Unocal is operator and holds an 80-percent working
interest. Unocal has made several discoveries in the Rapak PSC area, including
the deepwater Ranggas and Bangka fields. Water depth at Donggala ranges from
6,000 to 8,000 feet. The farm-in is subject to final approval by the Indonesian
government.
The Company and a partner also announced the award of the Muara Bakau PSC area,
located offshore East Kalimantan and inboard of the Company's Gula and Gendalo
discoveries. The Company's Muara Bakau Limited subsidiary will have a 50 percent
non-operating working interest in the PSC. Water depth in the Muara Bakau PSC
area ranges from 250 to 4,500 feet. The Muara Bakau PSC has a two-well
commitment in the first year.
China - East China Sea
----------------------
The Company has reached verbal agreement with China National Offshore Oil
Corporation, Sinopec Shanghai Offshore Oil and Gas Corporation and Royal Dutch
Shell in principle on the terms for a PSC covering the exploration and
development of natural gas resources on five offshore blocks in the Xihu Trough
area of the East China Sea, east of Shanghai. The parties have indicated a
desire to complete negotiations and sign a PSC by the end of March 2003. The
Company expects to hold a 20 percent working interest in the project.
Cautionary Statement
--------------------
This filing contains certain forward-looking statements about Unocal's future
production rates, commodity prices, dry hole costs, estimates of proved
reserves, future operations, capital expenditures, possible development
activities, drilling plans, expectations for government approvals and
business transactions. These statements are not guarantees of future
performance. The statements are based upon Unocal's current expectations
and beliefs and are subject to a number of known and unknown risks and
uncertainties that could cause actual results to differ materially from
those described in the forward looking statements. Actual results could
differ materially as a result of changes in commodity prices, development
and exploratory drilling results, the amounts of the Company's operating
cash flow and other capital resources available to fund its capital
expenditures, government approvals, regulatory, geological, operating
and economic considerations, and other factors discussed on pages 59 to 61
of Unocal's amended 2001 Annual Report on Form 10-K/A (copies of which pages
are attached as Exhibit 99 to this report and incorporated herein by reference)
and in subsequent reports.
-5-
CONSOLIDATED EARNINGS (UNAUDITED) UNOCAL CORPORATION
For the Three Months For the Twelve Months
Ended December 31, Ended December 31,
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Millions of dollars except per share amounts 2002 2001 2002 2001
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Revenues
Sales and operating revenues $ 1,519 $ 1,201 $ 5,179 $ 6,664
Interest, dividends and miscellaneous income 13 37 30 64
Gain on sales of assets 40 25 42 24
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Total revenues 1,572 1,263 5,251 6,752
Costs and other deductions
Crude oil, natural gas and product purchases 577 351 1,701 2,492
Operating expense 378 365 1,292 1,376
Administrative and general expense 37 26 151 122
Depreciation, depletion and amortization 249 253 973 967
Impairments 20 118 47 118
Dry hole costs 26 35 107 175
Exploration expense 66 80 246 252
Interest expense 45 47 179 192
Property and other operating taxes 19 17 60 77
Distributions on convertible preferred securities of subsidiary trust 9 9 33 33
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Total costs and other deductions 1,426 1,301 4,789 5,804
Earnings from equity investments 31 16 154 144
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Earnings (loss) from continuing operations before
income taxes and minority interests 177 (22) 616 1,092
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Income taxes 77 5 280 452
Minority interests 4 3 6 41
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Earnings (loss) from continuing operations 96 (30) 330 599
Discontinued operations
Refining, marketing and transportation
Gain on disposal (net of tax) - 1 1 17
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Earnings from discontinued operations - 1 1 17
Cumulative effect of accounting change - - - (1)
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Net earnings (loss) $ 96 $ (29) $ 331 $ 615
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Basic earnings (loss) per share of common stock (a)
Continuing operations $ 0.38 $ (0.13) $ 1.34 $ 2.45
Net earnings $ 0.38 $ (0.12) $ 1.34 $ 2.52
Diluted earnings (loss) per share of common stock (b)
Continuing operations $ 0.38 $ (0.13) $ 1.34 $ 2.43
Net earnings $ 0.38 $ (0.12) $ 1.34 $ 2.50
Cash dividends declared per share of common stock $ 0.20 $ 0.20 $ 0.80 $ 0.80
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(a) Basic weighted average shares outstanding (in thousands) 253,526 243,994 246,759 243,568
(b) Diluted weighted average shares outstanding (in thousands) 254,775 244,771 247,679 256,774
-6-
CONDENSED CONSOLIDATED BALANCE SHEET (UNAUDITED) UNOCAL CORPORATION
At December 31,
-------------------------------
Millions of dollars 2002 2001
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Assets
Cash and cash equivalents $ 168 $ 190
Other current assets - net 1,217 1,105
Investments and long-term receivables - net 1,044 1,405
Properties - net 7,879 7,484
Goodwill 112 30
Other assets 360 211
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Total assets $ 10,780 $ 10,425
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Liabilities and Stockholders' Equity
Current liabilities (a) $ 1,661 $ 1,422
Long-term debt and capital leases 2,992 2,897
Deferred income taxes 593 627
Other deferred credits and liabilities 1,439 1,314
Subsidiary stock subject to repurchase - 70
Minority interests 275 449
Convertible preferred securities of a subsidiary trust 522 522
Stockholders' equity 3,298 3,124
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Total liabilities and stockholders' equity $ 10,780 $ 10,425
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(a) Includes current portion of long-term debt of: 5 9
-7-
CONDENSED CONSOLIDATED CASH FLOWS (UNAUDITED) UNOCAL CORPORATION
Years Ended December 31,
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Millions of dollars 2002 2001
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Cash Flows from Operating Activities
Net earnings $ 331 $ 615
Adjustments to reconcile net earnings to
net cash provided by operating activities
Depreciation, depletion and amortization 973 967
Impairments 47 118
Dry hole costs 107 175
Amortization of exploratory leasehold costs 98 95
Deferred income taxes 22 81
Gain on sales of assets (pre-tax) (42) (24)
Gain on disposal of discontinued operations (pre-tax) (2) (27)
Earnings applicable to minority interests 6 41
Other (74) 31
Working capital and other changes related to operations 106 53
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Net cash provided by operating activities 1,572 2,125
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Cash Flows from Investing Activities
Capital expenditures (includes dry hole costs) (1,670) (1,727)
Major acquisitions - (646)
Proceeds from sales of assets 162 81
Proceeds from sale of discontinued operations 3 25
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Net cash used in investing activities (1,505) (2,267)
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Cash Flows from Financing Activities
Long-term borrowings 585 519
Reduction of long-term debt and capital lease obligations (495) (225)
Minority interests (8) (17)
Repurchases of common stock - -
Proceeds from issuance of common stock 20 15
Dividends paid on common stock (196) (195)
Other 5 -
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Net cash provided by (used in) financing activities (89) 97
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Decrease in cash and cash equivalents (22) (45)
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Cash and cash equivalents at beginning of year 190 235
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Cash and cash equivalents at end of year $ 168 $ 190
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-8-
OPERATING HIGHLIGHTS UNOCAL CORPORATION
For the Three Months For the Twelve Months
Ended December 31, Ended December 31,
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2002 2001 2002 2001
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North America Net Daily Production
Liquids (thousand barrels)
Lower 48 (a) (b) 46 59 52 59
Alaska 23 26 24 25
Canada 18 19 18 16
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Total liquids 87 104 94 100
Natural gas - dry basis (million cubic feet)
Lower 48 (a) (b) 659 860 719 905
Alaska 68 101 76 103
Canada 91 89 91 101
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Total natural gas 818 1,050 886 1,109
North America Average Prices (excluding hedging activities) (c) (d)
Liquids (per barrel)
Lower 48 $ 25.20 $ 18.27 $ 22.85 $ 23.35
Alaska $ 26.96 $ 22.36 $ 24.21 $ 24.69
Canada $ 19.58 $ 13.49 $ 20.10 $ 18.53
Average $ 24.46 $ 18.48 $ 22.68 $ 22.90
Natural gas (per mcf)
Lower 48 $ 3.77 $ 2.28 $ 3.01 $ 4.14
Alaska $ 1.20 $ 1.57 $ 1.42 $ 1.37
Canada $ 3.50 $ 2.37 $ 2.67 $ 4.34
Average $ 3.51 $ 2.22 $ 2.83 $ 3.89
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North America Average Prices (including hedging activities) (c) (d)
Liquids (per barrel)
Lower 48 $ 25.19 $ 18.75 $ 22.87 $ 23.41
Alaska $ 26.96 $ 22.36 $ 24.21 $ 24.69
Canada $ 19.58 $ 13.49 $ 20.10 $ 18.53
Average $ 24.45 $ 18.74 $ 22.69 $ 22.93
Natural gas (per mcf)
Lower 48 $ 3.75 $ 2.50 $ 3.07 $ 4.23
Alaska $ 1.20 $ 1.57 $ 1.42 $ 1.37
Canada $ 3.31 $ 2.37 $ 2.66 $ 3.17
Average $ 3.47 $ 2.40 $ 2.88 $ 3.85
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(a)Includes proportional shares of production of equity investees.
(b)Includes minority interest shares of :
Liquids 3 9 7 9
Natural gas 41 104 82 102
Barrels oil equivalent 10 26 21 26
(c)Excludes Trade segment margins.
(d)Excludes gains/losses on derivative positions not accounted for as hedges
and ineffective portions of hedges.
-9-
OPERATING HIGHLIGHTS (CONTINUED) UNOCAL CORPORATION
For the Three Months For the Twelve Months
Ended December 31, Ended December 31,
------------------------------------------
2002 2001 2002 2001
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International Net Daily Production (e)
Liquids (thousand barrels)
Far East 53 57 53 51
Other (a) 21 19 20 19
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Total liquids 74 76 73 70
Natural gas - dry basis (million cubic feet)
Far East 823 782 847 829
Other (a) 96 69 93 65
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Total natural gas 919 851 940 894
International Average Prices (f)
Liquids (per barrel)
Far East $ 25.68 $ 18.68 $ 22.88 $ 22.50
Other $ 27.55 $ 19.11 $ 25.47 $ 24.15
Average $ 26.23 $ 18.80 $ 23.57 $ 22.97
Natural gas (per mcf)
Far East $ 2.62 $ 2.45 $ 2.60 $ 2.52
Other $ 2.83 $ 2.43 $ 2.72 $ 2.75
Average $ 2.64 $ 2.45 $ 2.61 $ 2.54
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Worldwide Net Daily Production (a) (b) (e)
Liquids (thousand barrels) 161 180 167 170
Natural gas - dry basis (million cubic feet) 1,737 1,901 1,826 2,003
Barrels oil equivalent (thousands) 451 497 471 504
Worldwide Average Prices (excluding hedging activities) (c) (d)
Liquids (per barrel) $ 25.29 $ 18.62 $ 23.07 $ 22.93
Natural gas (per mcf) $ 3.04 $ 2.32 $ 2.72 $ 3.27
Worldwide Average Prices (including hedging activities) (c) (d)
Liquids (per barrel) $ 25.28 $ 18.77 $ 23.07 $ 22.95
Natural gas (per mcf) $ 3.02 $ 2.42 $ 2.74 $ 3.25
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(a) Includes proportional shares of production of equity investees.
(b) Includes minority interest shares of :
Liquids 3 9 7 9
Natural gas 41 104 82 102
Barrels oil equivalent 10 26 21 26
(c)Excludes Trade segment margins.
(d)Excludes gains/losses on derivative positions not accounted for as hedges
and ineffective portions of hedges.
(e)International production is presented utilizing the economic interest method.
(f)International did not have any hedging activities.
-10-
Item 7. Financial Statements and Exhibits.
(c) Exhibits
99. Pages 59-61 of Unocal's Amended 2001 Annual Report on Form 10-K/A -
Cautionary Statement for Purposes of the "Safe-Harbor" Provisions of the
Private Securities Litigation Reform Act of 1995.
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)
Date: February 5, 2003 By: /s/ JOE D. CECIL
------------------ -------------------------------
Joe D. Cecil
Vice President and Comptroller
-11-