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) October 24, 2002
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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.
Third Quarter 2002 and Year-To-Date Results
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Unocal Corporation's net earnings were $99 million, or 41 cents per share
(diluted), in the third quarter of 2002 compared with $102 million, or 42 cents
per share (diluted), in the third quarter of 2001. For the nine months period of
2002, net earnings were $235 million, or 96 cents per share (diluted), compared
with $644 million, or $2.59 per share (diluted), for the same period a year ago.
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
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Millions of dollars 2002 2001 2002 2001
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Earnings from continuing operations $ 99 $ 102 $ 234 $ 629
Earnings from discontinued operations - - 1 16
Cumulative effect of accounting change - - - (1)
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Net earnings $ 99 $ 102 $ 235 $ 644
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Continuing Operations
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Third Quarter Results: Earnings from continuing operations decreased primarily
due to lower natural gas production compared with the same period a year ago,
principally in the Lower 48 operations, which reflected lower Gulf of Mexico
natural gas production stemming primarily from a decline in Muni field
production (7 MMcf/d, net of royalty, in the third quarter of 2002 versus 140
MMcf/d, net of royalty, in the third quarter of 2001), the effect of reduced
second-half 2001 drilling activity compared with the first half of 2001, and
storm-related production curtailments in the Gulf of Mexico. The lower
production in the Lower 48 operations was partially offset by higher natural gas
production from International operations. Worldwide net daily production in the
third quarter of 2002 averaged 466,000 barrels-of-oil equivalent ("BOE") per day
compared with 506,000 BOE per day a year ago. The lower worldwide production
reduced net earnings by approximately $30 million. The third quarter of 2002
also included an after-tax loss of $5 million in mark-to-market accruals and
realized gains/losses for non-hedge commodity derivatives recorded by the
Company's Northrock Resources Ltd. ("Northrock") subsidiary, compared with an
after-tax gain of $1 million in the same period a year ago.
Higher liquids prices partially offset the decline in net earnings by
approximately $10 million. In the third quarter of 2002, the Company's worldwide
average liquids price was $24.19 per barrel, which was an increase of $1.32 per
barrel, or 6 percent, from the same period a year ago. The Company's hedging
program lowered the average liquids price by one cent in the third quarter of
2002 while the third quarter of 2001 included a gain of one cent per barrel from
hedging activities. Dry hole costs and exploration expense were lower in the
third quarter of 2002 compared to the same period a year ago primarily in
International operations, and positively impacted net earnings by approximately
$15 million. In addition, improved margins from Midstream operations coupled
with improved carbon and mineral results (which are included in Corporate and
Other segment earnings) positively impacted net earnings by approximately $10
million. After-tax provisions for environmental and litigation matters were $22
million in the third quarter of 2002, compared with $26 million in the same
period a year ago.
Nine Months Results: Earnings from continuing operations were $234 million, or
96 cents per share (diluted), in the nine months period of 2002, compared with
$629 million, or $2.53 per share (diluted), for the same period a year ago. The
decrease was primarily due to lower commodity prices and lower worldwide
production. Lower natural gas prices reduced net earnings by approximately $190
million, while lower liquids prices reduced net earnings by approximately $50
million. The Company's worldwide average natural gas price, including a benefit
of 4 cents per Mcf from hedging activities, was $2.65 per Mcf for the nine
months period of 2002, which was a decrease of 86 cents per Mcf or 25 percent
from the $3.51 per Mcf, including a loss of six cents per Mcf from hedging
activities, from the same period a year ago. In the nine months period of 2002,
the Company's worldwide average liquids price was $21.77 per barrel, including a
benefit of one cent per barrel from hedging activities, which was a decrease of
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$2.12 per barrel, or 9 percent, from the $23.89 per barrel price, including a
loss of 3 cents per barrel from hedging activities, from the same period a year
ago.
The results in the nine months period of 2002 were impacted by lower natural gas
production compared with the same period a year ago, which reduced net earnings,
by approximately $165 million. Worldwide, net daily production in the nine
months period of 2002 averaged 476,000 BOE per day, compared with 506,000 BOE
per day a year ago. 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 (11 MMcf/d, net of royalty, in the
nine months period of 2002 versus 107 MMcf/d, net of royalty, for the same
period a year ago) and the reduction in the second-half 2001 drilling activity.
The lower production in the Lower 48 operations was partially offset by higher
production from International operations.
The results in the nine months period of 2002 included the $12 million after-tax
impairment in Alaska and the $12 million after-tax restructuring provision for
the Gulf Region business unit. The nine months period of 2002 included an
after-tax loss of $5 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 $5 million in the same period a
year ago.
These negative results in the nine months period of 2002 were partially offset
by lower dry hole costs compared with the same period a year ago, which
contributed approximately $40 million to net earnings. In addition, after-tax
provisions for environmental and litigation matters were $56 million in the nine
months period of 2002, compared with $71 million in the same period a year ago.
The nine months period results of 2002 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 and related costs and a
$2 million after-tax gain adjustment related to a Lower 48 prior year asset
sale.
Discontinued Operations
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The nine months period of 2002 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 total after-tax
gain in the comparable period of 2001 was $16 million, or 6 cents per share
(diluted).
Cumulative Effect of Accounting Change
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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".
Revenues
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Total revenues from continuing operations for the third quarter of 2002 were
$1.29 billion, compared with $1.58 billion for the same period a year ago. The
decrease in the third quarter revenues primarily reflected lower domestic U.S.
natural gas and liquids production and reduced marketing activity related to the
Company's domestic equity crude production. For the nine months period of 2002,
total revenues from continuing operations were $3.68 billion, compared with
$5.49 billion for the same period a year ago. The decrease in the nine months
revenues 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.
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Financial Condition
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Cash flows from operating activities, including discontinued operations and
working capital and other changes, were $1.23 billion for the nine months period
of 2002 compared to $1.78 billion in the same period a year ago. This decrease
principally reflected the effects of lower worldwide average natural gas and
liquids prices and lower production volumes.
Capital expenditures were $1.25 billion for the nine months period of 2002,
compared with $1.26 billion during the same period a year ago. The 2001 capital
spending excluded $536 million for major acquisitions.
The Company's total consolidated debt, including current maturities, at the end
of September 2002, was $3.08 billion, compared with $2.91 billion at the end of
2001. This increase was primarily due to $437 million in commercial paper
borrowings, the proceeds of which were used to refinance maturing debt and for
general corporate purposes. The increase in the debt level from the commercial
paper borrowing was partially offset by retiring $152 million in maturing
medium-term notes during the nine months period of 2002. In addition, the
Company's Northrock subsidiary redeemed its $35 million "Series A" and $40
million "Series B" senior U.S. dollar-denominated notes.
Fourth Quarter and Full Year 2002 Outlook
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The Company estimates net earnings per share to be between 50 and 60 cents in
the fourth quarter of 2002. The fourth quarter forecast assumes average NYMEX
benchmark prices of $29.75 per barrel of crude oil and $4.10 per million British
thermal units ("MMBtus") for North America natural gas. The fourth quarter
forecasted earnings are expected to change 4 cents per share for every $1 change
in its average worldwide realized price for crude oil and 2 cents per share for
every 10-cent change in the Company's average realized North America natural gas
price. The fourth quarter forecast also includes pre-tax dry hole costs of $25
to $35 million. The Company estimates net earnings per share to be between $1.46
to $1.56 for the full year 2002.
Early in the fourth quarter of 2002, the Company sustained significant
production losses in the Gulf of Mexico as a result of Hurricane Lili, which
affected the Eastern Gulf of Mexico around the Company's production base in Ship
Shoal, Eugene Island and South Marsh Island. Production shut-ins from the storm
and the resulting damage to facilities will have a significant effect on fourth
quarter 2002 production. Production losses from shut-ins began on October 2 and
were as high as 75,000 BOE per day. By October 10 most of the shut-in production
from facilities that did not sustain major damage was restarted. Approximately
15,000 BOE per day remains shut in as major facility damage assessments and
recovery plans were being completed. The Company has insurance coverage for the
damages incurred, subject to a $15 million deductible. The Eastern Gulf area is
also where the Company was planning to spend the majority of its development and
workover activities in the third and fourth quarters of 2002. A significant
number of these projects are currently delayed pending facility repair. The
impact of these project delays is estimated to be around 4,000 BOE per day.
The Company currently expects to resume production by the end of the year from
the remaining damaged facilities. The Company estimates that hurricane-related
impacts will lower fourth quarter production by 15,000 to 23,000 BOE per day.
The Company was expecting production to be essentially flat with the third
quarter, with seasonal declines in Thailand canceling out growth in Canada and
Pure Resources. The Company's best estimates for fourth quarter production,
including the effect of Hurricane Lili, are between 445,000 and 460,000 BOE per
day. The full-year 2002 production forecast is expected to average between
469,000 and 472,000 BOE per day.
Recent declines in the equity markets and interest rates have had a negative
impact on the Unocal Retirement Plan ("Plan"). The fair value of the pension
trust assets at October 22, 2002 was below the Plan's accumulated benefit
obligation. Without a substantial rebound in the equity markets before year-end,
a calculation based on the current fair value of pension assets would require
the Company to take an after-tax charge to stockholders' equity (accumulated
other comprehensive income) at December 31, 2002
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for an estimated amount of $330 million. The actual charge to accumulated other
comprehensive income will vary primarily with future 2002 changes in the equity
markets and the resultant change in the fair value of Plan assets, but will have
no impact on 2002 net earnings.
For the full-year 2002, pension expense related to the Company's U.S. based
employees is expected to be $14 million after-tax, an increase of approximately
$25 million after-tax compared to the full-year 2001. Lower returns and declines
on plan assets and the use of a lower discount rate to measure benefit-related
liabilities are the principal factors behind the increase in current year
expense. Furthermore, continued lower returns and declines on Plan assets would
result in increased pension expense in future years and could result in
accelerating the need to make cash contributions to the Plan.
2003 Production Outlook
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The Company expects crude oil and natural gas production in 2003 to be between
2.5 percent and 5 percent above the 2002 level.
The production outlook is based on an expected capital budget of about $1.7
billion, essentially unchanged from 2002. Capital spending on major developments
will continue to account for an increasingly larger percentage of the company's
overall capital spending profile, at the expense of small, shorter term,
production-adding projects.
The keystone of the 2003 production growth forecast is the start of new
production from the deepwater West Seno oil and gas field in Indonesia, which is
expected to come on line at the beginning of the second quarter of 2003. The
Phase One development has peak production potential of more than 52,000 BOE per
day net to Unocal, increasing to more than 65,000 BOE per day with Phase Two.
Modest growth is also expected in Thailand, with continued expected strong gas
demand and the full-year effect of the Pailin 2 gas and Yala/Plamuk oil
developments, which are currently producing at almost 24,000 BOE per day (net).
North America production is expected to be relatively unchanged from 2002, as
anticipated increases in Canada are offset by declines in the Lower 48. This
assumes a modest degree of success with the company's emerging deep shelf
exploration program and does not include the impact of any divestitures that may
occur.
Five-year Outlook
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Longer term, the Company sees five-year annual production growth rates of
between 5 and 7 percent, fueled by the Company's backlog of major development
projects.
Currently sanctioned projects include West Seno Phases One and Two, Azerbaijan
International Operating Company ("AIOC") Phases One and Two, Mad Dog (Gulf of
Mexico) and South Kenai (Alaska) gas. The Company expects to make sanction
decisions on AIOC Phase Three, Ranggas and Merah Besar in Indonesia, K2 and
Trident in the deepwater Gulf of Mexico, and Arthit in Thailand, each of which
could impact production in the five-year timeframe.
Unocal will also continue to take steps to reduce the decline rate of its mature
legacy production base. In North America, Unocal's current production base is
equally split between the higher decline properties on the Gulf of Mexico shelf
and the lower decline onshore U.S. and Canadian properties. Success with the
deep-shelf program should have the effect of offsetting decline rates on the
shelf while the company continues to grow its Canada and onshore U.S. positions.
In Indonesia, the company will begin substituting lower cost deepwater gas
production for marginal shelf gas production beginning in 2003. In Thailand and
Myanmar, decline rates are immaterial as production is managed as a function of
market demand and there are hydrocarbon resources available to meet the existing
sales contracts.
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Beyond 2007
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The backlog of major projects extends well beyond the five-year horizon, and
includes the monetization of gas fields in deepwater Indonesia, Bangladesh, and
Vietnam. The next phase of Unocal's future will be characterized by bringing on
existing major developments, sanctioning existing discoveries, continuing
exploration programs, and moving the monetization of Asian gas resources
forward.
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CONSOLIDATED EARNINGS (UNAUDITED) UNOCAL CORPORATION
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
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Millions of dollars except per share amounts 2002 2001 2002 2001
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Revenues
Sales and operating revenues $ 1,287 $ 1,573 $ 3,660 $ 5,463
Interest, dividends and miscellaneous income (3) 8 17 27
Gain (loss) on sales of assets 1 (2) 2 (1)
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Total revenues 1,285 1,579 3,679 5,489
Costs and other deductions
Crude oil, natural gas and product purchases 401 617 1,124 2,141
Operating expense 314 352 914 1,011
Administrative and general expense 34 25 114 96
Depreciation, depletion and amortization 245 246 724 714
Impairments 6 - 27 -
Dry hole costs 40 53 81 140
Exploration expense 60 61 180 172
Interest expense 40 48 134 145
Property and other operating taxes 7 19 41 60
Distributions on convertible preferred securities of subsidiary trust 8 8 24 24
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Total costs and other deductions 1,155 1,429 3,363 4,503
Earnings from equity investments 35 37 123 128
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Earnings from continuing operations before
income taxes and minority interests 165 187 439 1,114
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Income taxes 68 77 203 447
Minority interests (2) 8 2 38
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Earnings from continuing operations 99 102 234 629
Discontinued operations
Refining, marketing and transportation
Gain on disposal (net of tax) - - 1 16
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Earnings from discontinued operations - - 1 16
Cumulative effect of accounting change - - - (1)
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Net earnings $ 99 $ 102 $ 235 $ 644
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Basic earnings per share of common stock (a)
Continuing operations $ 0.41 $ 0.42 $ 0.96 $ 2.59
Net earnings $ 0.41 $ 0.42 $ 0.96 $ 2.65
Diluted earnings per share of common stock (b)
Continuing operations $ 0.41 $ 0.42 $ 0.96 $ 2.53
Net earnings $ 0.41 $ 0.42 $ 0.96 $ 2.59
Cash dividends declared per share of common stock $ 0.20 $ 0.20 $ 0.60 $ 0.60
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(a) Basic weighted average shares outstanding (in thousands) 244,664 243,601 244,503 243,426
(b) Diluted weighted average shares outstanding (in thousands) 245,226 244,566 245,378 256,812
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CONDENSED CONSOLIDATED BALANCE SHEET (UNAUDITED) UNOCAL CORPORATION
At September 30, At December 31,
Millions of dollars 2002 2001
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Assets
Cash and cash equivalents $ 275 $ 190
Other current assets - net 910 1,105
Investments and long-term receivables - net 1,549 1,405
Properties - net 7,784 7,514
Other assets 282 211
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Total assets $ 10,800 $ 10,425
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Liabilities and Stockholders' Equity
Current liabilities (a) $ 1,458 $ 1,422
Long-term debt and capital leases 3,070 2,897
Deferred income taxes 731 627
Other deferred credits and liabilities 1,301 1,314
Subsidiary stock subject to repurchase 111 70
Minority interests 425 449
Convertible preferred securities of a subsidiary trust 522 522
Stockholders' equity 3,182 3,124
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Total liabilities and stockholders' equity $ 10,800 $ 10,425
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(a) Includes current portion of Long-term debt of: 8 9
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CONDENSED CONSOLIDATED CASH FLOWS (UNAUDITED) UNOCAL CORPORATION
For the Nine Months
Ended September 30,
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Millions of dollars 2002 2001
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Cash Flows from Operating Activities
Net earnings $ 235 $ 644
Adjustments to reconcile net earnings to
net cash provided by operating activities
Depreciation, depletion and amortization 724 714
Impairments 27 -
Dry hole costs 81 140
Amortization of exploratory leasehold costs 74 69
Deferred income taxes 25 113
(Gain) loss on sales of assets (pre-tax) (2) 1
(Gain) on disposal of discontinued operations (pre-tax) (2) (25)
Earnings applicable to minority interests 2 38
Other (56) 115
Working capital and other changes related to operations 124 (29)
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Net cash provided by operating activities 1,232 1,780
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Cash Flows from Investing Activities
Capital expenditures (includes dry hole costs) (1,248) (1,257)
Major acquisitions - (536)
Proceeds from sales of assets 61 26
Proceeds from sale of discontinued operations 3 25
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Net cash used in investing activities (1,184) (1,742)
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Cash Flows from Financing Activities
Long-term borrowings 437 467
Reduction of long-term debt and capital lease obligations (267) (221)
Minority interests (6) (17)
Repurchases of common stock - -
Proceeds from issuance of common stock 19 14
Dividends paid on common stock (147) (146)
Other 1 1
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Net cash provided by financing activities 37 98
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Net increase in cash and cash equivalents 85 136
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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 period $ 275 $ 371
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OPERATING HIGHLIGHTS UNOCAL CORPORATION
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
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2002 2001 2002 2001
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North America Net Daily Production
Liquids (thousand barrels)
Lower 48 (a) (b) 52 60 54 58
Alaska 24 26 25 25
Canada 16 16 17 15
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Total liquids 92 102 96 98
Natural gas - dry basis (million cubic feet)
Lower 48 (a) (b) 716 939 740 922
Alaska 61 83 79 104
Canada 90 92 91 105
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Total natural gas 867 1,114 910 1,131
North America Average Prices (excluding hedging activities) (c) (d)
Liquids (per barrel)
Lower 48 $ 24.76 $ 23.08 $ 22.19 $ 24.71
Alaska $ 22.17 $ 21.58 $ 19.41 $ 22.18
Canada $ 22.70 $ 20.89 $ 20.29 $ 20.74
Average $ 23.70 $ 22.35 $ 21.12 $ 23.44
Natural gas (per mcf)
Lower 48 $ 2.95 $ 2.71 $ 2.77 $ 4.71
Alaska $ 1.20 $ 1.57 $ 1.48 $ 1.30
Canada $ 2.08 $ 2.69 $ 2.38 $ 4.90
Average $ 2.73 $ 2.62 $ 2.61 $ 4.40
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North America Average Prices (including hedging activities) (c) (d)
Liquids (per barrel)
Lower 48 $ 24.74 $ 23.11 $ 22.22 $ 24.63
Alaska $ 22.17 $ 21.58 $ 19.41 $ 22.18
Canada $ 22.70 $ 20.89 $ 20.29 $ 20.74
Average $ 23.69 $ 22.37 $ 21.14 $ 23.39
Natural gas (per mcf)
Lower 48 $ 2.97 $ 2.97 $ 2.86 $ 4.76
Alaska $ 1.20 $ 1.57 $ 1.48 $ 1.30
Canada $ 2.10 $ 2.76 $ 2.44 $ 3.40
Average $ 2.74 $ 2.85 $ 2.69 $ 4.29
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(a) Includes proportional shares of production of equity investees.
(b) Includes minority interest shares of :
Liquids 8 9 8 9
Natural gas 94 111 96 100
Barrels oil equivalent 24 27 24 25
(c) Excludes Trade segment margins.
(d) Excludes gains/losses on derivative positions not accounted for
as hedges and ineffective portions of hedges.
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OPERATING HIGHLIGHTS (CONTINUED) UNOCAL CORPORATION
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
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2002 2001 2002 2001
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International Net Daily Production (e)
Liquids (thousand barrels)
Far East 52 49 53 49
Other (a) 20 19 20 19
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Total liquids 72 68 73 68
Natural gas - dry basis (million cubic feet)
Far East 859 833 855 845
Other (a) 83 66 79 64
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Total natural gas 942 899 934 909
International Average Prices (f)
Liquids (per barrel)
Far East $ 23.93 $ 23.04 $ 21.95 $ 24.02
Other $ 26.94 $ 25.27 $ 24.62 $ 26.04
Average $ 24.80 $ 23.65 $ 22.62 $ 24.60
Natural gas (per mcf)
Far East $ 2.68 $ 2.62 $ 2.59 $ 2.54
Other $ 2.80 $ 2.80 $ 2.70 $ 2.90
Average $ 2.69 $ 2.63 $ 2.60 $ 2.57
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Worldwide Net Daily Production (a) (b) (e)
Liquids (thousand barrels) 164 170 169 166
Natural gas - dry basis (million cubic feet) 1,809 2,013 1,844 2,040
Barrels oil equivalent (thousands) 466 506 476 506
Worldwide Average Prices (excluding hedging activities) (c) (d)
Liquids (per barrel) $ 24.20 $ 22.86 $ 21.76 $ 23.92
Natural gas (per mcf) $ 2.71 $ 2.63 $ 2.61 $ 3.57
Worldwide Average Prices (including hedging activities) (c) (d)
Liquids (per barrel) $ 24.19 $ 22.87 $ 21.77 $ 23.89
Natural gas (per mcf) $ 2.72 $ 2.75 $ 2.65 $ 3.51
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(a) Includes proportional shares of production of equity investees.
(b) Includes minority interest shares of :
Liquids 8 9 8 9
Natural gas 94 111 96 100
Barrels oil equivalent 24 27 24 25
(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.
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This filing contains certain forward-looking statements about Unocal's expected
earnings, production rates, commodity prices, capital spending, insurance
recoveries, dry hole costs, future operations, possible development activities
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 factors discussed in Unocal's amended 2001 Annual
Report on Form 10-K/A and subsequent reports.
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
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(Registrant)
Date: October 24, 2002 By: /s/ JOHN A. BRIFFETT
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John A. Briffett
Assistant Comptroller
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