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) June 10, 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
Second Quarter 2002 and Year-To-Date Results
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Unocal Corporation's net earnings were $114 million, or 46 cents per share
(diluted), in the second quarter of 2002 compared with $247 million, or 99 cents
per share (diluted), in the second quarter of 2001.
For the Three Months For the Six Months
Ended June 30, Ended June 30,
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Millions of dollars 2002 2001 2002 2001
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Earnings from continuing operations $ 113 $ 235 $ 135 $ 527
Earnings from discontinued operations 1 12 1 16
Cumulative effect of accounting change - - - (1)
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Net earnings $ 114 $ 247 $ 136 $ 542
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Earnings from continuing operations were $113 million, or 46 cents per share
(diluted), in the second quarter of 2002 compared with $235 million, or 95 cents
per share (diluted), for the same period a year ago. The decrease was primarily
due to lower natural gas production and lower prices for natural gas and liquids
(crude oil, condensate and natural gas liquids). The second quarter of 2002 was
impacted by lower 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 from a decline in Muni field production (10
MMcf/d net of royalty in the second quarter of 2002 versus 126 MMcf/d net of
royalty in the second quarter of 2001) and reduced second-half 2001 drilling
activity, compared with the first half of 2001, in response to lower commodity
prices. Worldwide, net daily production in the second quarter of 2002 averaged
486,000 barrels-of-oil equivalent ("BOE") per day, compared with 516,000 BOE per
day a year ago. The lower worldwide production reduced net earnings by
approximately $70 million.
Lower natural gas prices reduced net earnings by approximately $25 million,
while lower liquids prices reduced net earnings by approximately $15 million.
The Company's worldwide average natural gas price, which was not impacted by
hedging activities, was $2.80 per thousand cubic feet ("Mcf") in the second
quarter of 2002, which was a decrease of 61 cents per Mcf, or 18 percent, from
the same period a year ago. The Company's second quarter of 2001 included a loss
of one cent per Mcf from hedging activities. In the second quarter of 2002, the
Company's worldwide average liquids price was $22.63 per barrel, which was a
decrease of $1.70 per barrel, or 7 percent, from the same period a year ago. The
Company's hedging program had no impact on the average liquids price in the
second quarter of 2002 while the second quarter of 2001 included a loss of 5
cents per barrel from hedging activities.
The second quarter of 2002 also was negatively impacted by a $12 million
after-tax impairment in Alaska and a $12 million after-tax restructuring
provision for the Gulf Region business unit. After-tax provisions for
environmental and litigation matters were $13 million in the second quarter of
2002, compared with $14 million in the same period a year ago. The second
quarter of 2002 also included an after-tax gain of $4 million in mark-to-market
accruals and realized gains/losses for non-hedge commodity derivatives recorded
by the Company's Northrock Resources Ltd. ("Northrock") subsidiary, compared
with an after-tax gain of $21 million in the same period a year ago.
-1-
In the first six months of 2002, net earnings were $136 million, or 55 cents per
share (diluted), compared with $542 million, or $2.17 per share (diluted), for
the same period a year ago.
Earnings from continuing operations were $135 million, or 55 cents per share
(diluted), in the first six months of 2002, compared with $527 million, or $2.11
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 $155 million, while lower liquids
prices reduced net earnings by approximately $50 million. The Company's
worldwide average natural gas price, including a benefit of 6 cents per Mcf from
hedging activities, was $2.61 per Mcf for the first six months of 2002, which
was a decrease of $1.28 per Mcf or 33 percent from the $3.89 per Mcf, including
a loss of 3 cents per Mcf from hedging activities, from the same period a year
ago. In the first six months of 2002, the Company's worldwide average liquids
price was $20.53 per barrel, including a benefit of 2 cents per barrel from
hedging activities, which was a decrease of $3.92 per barrel or 16 percent from
the $24.45 per barrel, including a loss of 5 cents per barrel from hedging,
activities from the same period a year ago.
The results in the first six months of 2002 were also impacted by lower
production compared with the same period a year ago, which reduced net earnings
by approximately $190 million. The impact was principally in the Lower 48
operations, which reflected lower Gulf of Mexico natural gas production stemming
from the decline in Muni field production (13 MMcf/d net of royalty in the first
six months of 2002 versus 91 MMcf/d net of royalty for the first six months of
2001) and the reduction in the second-half 2001 drilling activity.
The results in the first six months 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. After-tax provisions for environmental and
litigation matters were $34 million in the first six months of 2002, compared
with $45 million in the same period a year ago. The first six months 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. The first six months of 2001
included an after-tax gain of $4 million in mark-to-market accruals and realized
gains/losses for non-hedge commodity derivatives by the Company's Northrock
subsidiary.
The second quarter 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 second quarter
of 2001 included a similar after-tax gain for $12 million, or 4 cents per share
(diluted). The total after-tax gain in the first six months of 2001 from
discontinued operations was $16 million, or 6 cents per share (diluted).
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-
The following table includes a reconciliation of consolidated net earnings to
adjusted after-tax earnings. Special items represent certain significant
transactions, the results of which are included in net earnings, that management
determines to be unrelated to or not representative of the Company's ongoing
operations. The purpose of the table is to provide the investment community
supplemental financial data in addition to the data prepared in accordance with
generally accepted accounting principles. The Company cautions that the adjusted
after-tax earnings presentation may not be comparable to similarly titled
measures of other companies.
For the Three Months For the Six Months
Ended June 30, Ended June 30,
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Millions of dollars 2002 2001 2002 2001
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Net earnings (a) $114 $ 247 $ 136 $ 542
Less: Earnings from discontinued operations 1 12 1 16
Less: Cumulative effect of accounting change - - - (1)
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Earnings from continuing operations 113 235 135 527
Special items:
Continuing operations
Litigation provisions (Lower 48) - - 1 -
Asset sales (Lower 48) - - 2 -
Restructuring (Lower 48) (12) - (12) -
Trading derivatives -- non-hedging (Canada) 4 21 - 4
Environmental and litigation
provisions (Corporate & Other) (13) (14) (35) (45)
Insurance settlements (Corporate & Other) - - 2 -
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Total special items from
continuing operations (21) 7 (42) (41)
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Adjusted after-tax earnings
(before special items) (a) $134 $ 228 $ 177 $ 568
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(a) Includes amounts attributable
to minority interests of: $ (3) $ (14) $ (4) $ (30)
Total revenues from continuing operations for the second quarter of 2002 were
$1.36 billion, compared with $1.70 billion for the same period a year ago. For
the six months period of 2002, total revenues from continuing operations were
$2.39 billion, compared with $3.91 billion for the same period a year ago. The
decreases, in both the quarter and six months results, primarily reflected lower
hydrocarbon commodity prices, lower domestic natural gas production and reduced
crude oil marketing activities.
Capital expenditures in the second quarter of 2002 were $440 million, compared
with $464 million, excluding major acquisitions, in the second quarter of 2001.
In the second quarter of 2001, major acquisitions included the acquisition by
the Company's, Pure Resources, Inc. ("Pure"), subsidiary of Hallwood Energy
Corporation ("Hallwood") for a cash outlay of $150 million. Capital expenditures
for the six months period of 2002 were $830 million, compared with $824 million,
excluding major acquisitions, in the same period a year ago. In the first six
months of 2001, major acquisitions included the acquisition by Pure of
properties from International Paper Company for $267 million and the Hallwood
acquisition.
The Company's total consolidated debt, including current maturities, at the end
of the second quarter of 2002 was $3.12 billion, compared with $2.91 billion at
the end of 2001. The debt-to-total capitalization ratio was 46 percent at the
end of the second quarter of 2002 compared with 44 percent at the end of 2001.
-3-
OPERATING HIGHLIGHTS UNOCAL CORPORATION
For the Three Months For the Six Months
Ended June 30, Ended June 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) 54 59 55 57
Alaska 25 24 25 24
Canada 17 15 18 15
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Total liquids 96 98 98 96
Natural gas - dry basis (million cubic feet)
Lower 48 (a) (b) 766 954 754 911
Alaska 77 93 89 115
Canada 92 85 91 112
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Total natural gas 935 1,132 934 1,138
North America Average Prices (excluding hedging activities) (c) (d)
Liquids (per barrel)
Lower 48 $23.48 $24.72 $20.92 $25.62
Alaska $20.86 $22.27 $18.03 $22.55
Canada $21.92 $20.84 $19.15 $20.65
Average $22.47 $23.54 $19.85 $24.05
Natural gas (per mcf)
Lower 48 $ 3.12 $ 4.62 $ 2.68 $ 5.73
Alaska $ 1.57 $ 1.20 $ 1.57 $ 1.20
Canada $ 2.90 $ 2.85 $ 2.53 $ 3.94
Average $ 2.96 $ 4.19 $ 2.55 $ 5.07
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North America Average Prices (including hedging activities) (c) (d)
Liquids (per barrel)
Lower 48 $23.47 $24.57 $20.97 $25.47
Alaska $20.86 $22.27 $18.03 $22.55
Canada $21.92 $20.84 $19.15 $20.65
Average $22.47 $23.45 $19.88 $23.96
Natural gas (per mcf)
Lower 48 $ 3.12 $ 4.62 $ 2.80 $ 5.69
Alaska $ 1.57 $ 1.20 $ 1.57 $ 1.20
Canada $ 2.97 $ 2.48 $ 2.62 $ 3.65
Average $ 2.97 $ 4.16 $ 2.66 $ 5.01
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(a) Includes proportional shares of production of equity investees.
(b) Includes minority interest shares of :
Liquids 9 9 9 8
Natural gas 98 106 98 95
Barrels oil equivalent 25 26 25 24
(c) Excludes Trade segment margins.
(d) Excludes gains/losses on derivative positions not accounted for as hedges
and ineffective portion of hedges.
-4-
OPERATING HIGHLIGHTS (CONTINUED) UNOCAL CORPORATION
For the Three Months For the Six Months
Ended June 30, Ended June 30,
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2002 2001 2002 2001
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International Net Daily Production (e)
Liquids (thousand barrels)
Far East 54 48 53 49
Other (a) 20 19 20 19
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Total liquids 74 67 73 68
Natural gas - dry basis (million cubic feet)
Far East 883 908 852 851
Other (a) 79 69 78 63
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Total natural gas 962 977 930 914
International Average Prices (f)
Liquids (per barrel)
Far East $22.50 $24.91 $20.95 $24.57
Other $23.91 $27.51 $23.03 $26.36
Average $22.84 $25.61 $21.43 $25.10
Natural gas (per mcf)
Far East $ 2.63 $ 2.54 $ 2.55 $ 2.51
Other $ 2.79 $ 2.92 $ 2.64 $ 2.90
Average $ 2.64 $ 2.56 $ 2.56 $ 2.54
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Worldwide Net Daily Production (a) (b) (e)
Liquids (thousand barrels) 170 165 171 164
Natural gas - dry basis (million cubic feet) 1,897 2,109 1,864 2,052
Barrels oil equivalent (thousands) 486 516 482 506
Worldwide Average Prices (excluding hedging activities) (c) (d)
Liquids (per barrel) $22.63 $24.38 $20.51 $24.50
Natural gas (per mcf) $ 2.80 $ 3.42 $ 2.55 $ 3.92
Worldwide Average Prices (including hedging activities) (c) (d)
Liquids (per barrel) $22.63 $24.33 $20.53 $24.45
Natural gas (per mcf) $ 2.80 $ 3.41 $ 2.61 $ 3.89
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(a) Includes proportional shares of production of equity investees.
(b) Includes minority interest shares of :
Liquids 9 9 9 8
Natural gas 98 106 98 95
Barrels oil equivalent 25 26 25 24
(c) Excludes Trade segment margins.
(d) Excludes gains/losses on derivative positions not accounted for as hedges
and ineffective portion of hedges.
(e) International production is presented utilizing the economic interest method.
(f) International did not have any hedging activities.
-5-
Third Quarter and Full Year 2002 Outlook
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The Company estimates net earnings per share to be between 45 to 55 cents in the
third quarter of 2002. The third quarter forecast assumes average NYMEX
benchmark prices of $26.75 per barrel of crude oil and $3.15 per million British
thermal units ("MMBtus") for North America natural gas. The third 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 Company estimates that net worldwide daily production for the third
quarter will average between 480,000 and 490,000 BOE. The third quarter forecast
also includes pre-tax dry hole costs of $30 to $40 million.
For the full-year 2002, the Company estimates net earnings per share to be
between $1.60 to $1.80. The full-year forecast assumes average NYMEX benchmark
prices of $25.10 per barrel of crude oil and $3.05 per MMBtus for North America
natural gas. The full-year forecasted earnings are expected to change 16 cents
per share for every $1 change in its average worldwide realized price for crude
oil and 8 cents per share for every 10-cent change in the Company's average
realized North America natural gas price. The Company estimates that net
worldwide daily production for the full-year will average in the lower end of
the range between 490,000 and 500,000 BOE. The anticipated production increase
through the remainder of 2002 reflects new projects in the Far East and Gulf of
Mexico. The full-year forecast also includes pre-tax dry hole costs of $110 to
$125 million.
The Company currently estimates that full-year 2002 capital expenditures will
approximate $1.7 billion.
-6-
Unocal Thailand Begins Production from Phase II of Pailin Field
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On July 1, 2002, the Company's Unocal Thailand, Ltd. ("Unocal Thailand"),
subsidiary started natural gas production from the Phase II development in the
northern part of Pailin field in the B12/27 concession area in the Gulf of
Thailand. The minimum daily contract quantity of natural gas sales from Phase II
("North Pailin") facilities is 165 gross MMcf/d, raising the gross contracted
natural gas sales from the Pailin field to 330 MMcf/d under an agreement with
PTT Public Co., Ltd. ("PTT"), the partially privatized state petroleum company.
North Pailin facilities have produced an average of 180 gross MMcf/d throughout
the month of July.
In addition, the North Pailin facilities have produced an average of 5,300 gross
barrels of condensate per day (b/d) throughout the month of July, raising total
condensate production from Pailin to more than 14,600 gross b/d.
Unocal Thailand is operator of the field and holds a 35 percent working interest
(31 percent net of royalty).
The Pailin field is Unocal Thailand's largest and most complex single project.
Unocal Thailand has installed 11 wellhead platforms and two processing platforms
to serve the entire field. Unocal Thailand and its co-venturers have invested
over $820 million in developing Pailin. Gas from the field is sold to PTT under
a 30-year gas sales agreement signed in 1996. Phase I production began at Pailin
in 1999. With the new production from North Pailin, gross natural gas production
from all the fields operated by Unocal Thailand now totals over 1 billion cubic
feet of gas per day for the Thai market.
Agreements Reached on Indonesia Geothermal Contracts
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On July 23, 2002, the Company's Unocal Geothermal of Indonesia, Ltd. ("UGI"),
subsidiary and Dayabumi Salak Pratama, Ltd. ("DSPL"), a 50-percent equity
investee of UGI, announced that they reached agreement over pricing and
production issues at the Gunung Salak geothermal project in Indonesia with PT.
PLN (Persero) ("PLN"), the Indonesian state-owned electricity company, and
Pertamina, the Indonesian state-owned oil and natural gas company.
Gunung Salak is a 330-megawatt geothermal production and electricity generation
project on the western side of the island of Java. UGI operates the steam fields
as a contractor to Pertamina and delivers geothermal steam to PLN, which
operates three electricity-generating plants at Salak. UGI also delivers steam
to DSPL for three generating plants that supply electricity to PLN on behalf of
Pertamina.
The new agreement extends the primary terms of the Joint Operation Contract and
Energy Sales Contract to 2040. The new agreement also includes a commitment by
PLN to accept as much steam and electricity as possible to meet increased demand
in the Java-Bali electricity distribution system. In addition, the agreement
reaffirms the Government of Indonesia guarantee of PLN's obligations to UGI,
DSPL, Pertamina and the project's lenders.
The new agreement lowers the selling price of electricity delivered by DSPL and
steam supplied to PLN by UGI. It also provides for payment by PLN of a portion
of the past due receivable balances to the Company while the Company foregoes a
portion of the receivables. Allowances for the uncollectable portion of the
unpaid receivables have previously been accrued on the Company's balance sheet.
With this agreement in place, the Company's Geothermal and Power business
segment is forecast to have after-tax earnings of $40 to $50 million in 2002,
compared with $11 million in 2001.
-7-
Agrium Litigation
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On June 10, 2002, a lawsuit was filed against the Company by Agrium Inc., a
Canadian corporation, and a U. S. subsidiary in the California Superior Court,
Los Angeles County (Agrium U.S. Inc. and Agrium Inc. v. Union Oil Company of
California, Case No. BC275407). The Company subsequently removed the case to the
U.S. District Court for the Central District of California (Case No. 02-04769
Nm).
The Agrium entities ("Agrium") allege numerous causes of action relating to
their purchase from the Company of a nitrogen-based fertilizer plant on the
Kenai Peninsula, Alaska, in September 2000. The primary allegations involve the
Company's obligation to supply natural gas to the plant pursuant to a Gas
Purchase and Sale Agreement (the "GPSA") between the parties. Agrium alleges
that the Company misrepresented the amount of gas reserves available for sale to
the plant as of the closing of the transaction and that the Company has failed
to develop additional reserves for sale to the plant. Agrium also alleges that
the Company misrepresented the condition of the general effluent sewer at the
plant and made misrepresentations regarding other environmental matters.
Agrium seeks damages in an unspecified amount for breach of such representations
and warranties, as well as for alleged misconduct by the Company in operating
and managing certain oil and gas leases and other facilities. Agrium also seeks
declaratory relief concerning the base price of gas under the GPSA, as well as
for the calculation of payments under a "Retained Earnout" covenant that
entitles the Company to certain contingent payments based on the price of
ammonia subsequent to the September 2000 closing. The complaint includes demands
for punitive damages and attorneys' fees.
Also on June 10, 2002, the Company filed a lawsuit against Agrium in the U.S.
District Court for the Central District of California (Union Oil Company of
California v. Agrium Inc. and Agrium U.S. Inc., Case No. 02-04518 Nm(Ctx)). The
Company seeks declaratory relief in its favor against the allegations of Agrium
set forth above and for judgment on the Retained Earnout in the amount of $16.6
million, together with interest accrued subsequent to May 31, 2002.
The Company believes that certain portions of its disputes with Agrium are
subject to binding arbitration under the terms of the GPSA, and has initiated
arbitration respecting the gas supply available under that agreement. Agrium
claims the dispute resolution provisions of the agreement for the sale of the
plant (the "PSA") supersede the arbitration provisions of the GPSA, and has
moved for an order enjoining the arbitration proceedings. The federal court
recently denied a motion by Agrium to temporarily restrain implementation of the
arbitration.
Agrium has filed motions to stay the Company's case, to enjoin implementation of
the arbitration and for Agrium's suit to be remanded to the state court. A
hearing on these motions is set for September 16, 2002.
The GPSA contains a contractual limit on liquidated damages of $25 million per
year, not to exceed a total of $50 million over the life of the agreement. In
addition, the PSA contains a limit on damages of $50 million. The Company
believes it has a meritorious defense to each of the Agrium claims, but that in
any event its exposure to damages for all disputes is limited by the agreements.
Agrium alleges that it is entitled to recover damages in excess of those
amounts.
-8-
Bangladesh Claim
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On July 2, 2002, the Company's Bermuda subsidiary Unocal Bangladesh Blocks
Thirteen and Fourteen, Ltd. (which was acquired in 1999 from Occidental
Petroleum Corporation and, prior to the July 22, 2002, completion of Bangladesh
name-change formalities, was still known in Bangladesh as Occidental of
Bangladesh Ltd.) ("OBL"), received from the Bangladesh Oil, Gas & Mineral
Corporation ("Petrobangla") a letter claiming, on behalf of the Bangladesh
government and Petrobangla, compensation allegedly due in the amount of $685
million for 246 billion cubic feet of recoverable natural gas allegedly "lost
and damaged" in a 1997 blowout and ensuing fire during the drilling by OBL, as
operator, of the Moulavi Bazar #1 ("MB #1") exploration well on the Blocks 13
and 14 production-sharing contract ("PSC") area in Northeast Bangladesh.
The Company and OBL believe that the claim vastly overstates the amount of
recoverable gas involved in the blowout.
Consistent with worldwide industry contracting practice, there was no provision
in the PSC for compensating the Bangladesh government or Petrobangla for
resources lost during the contractors' operations. Even if some form of
compensation were due, the Company and OBL believe that settlement compensation
for the blowout was fully addressed in a November 1998 Supplemental Agreement to
the PSC, which, among other matters, waived OBL's then 50-percent contractor's
share (as well as the then 50-percent contractor's share held by the Company's
Unocal Bangladesh, Ltd., subsidiary) of entitlement to the recovery of costs
incurred in the blowout, waived their right to invoke force majeure in
connection with the blowout, and reduced by five percentage points their
contractors' profit share (with a concomitant increase in Petrobangla's profit
share) of future production from the sands encountered by the MB #1 well to a
drill depth of 840 meters or, if the blowout sand reservoir were not deemed
commercial, from other commercial fields in the Moulavi Bazar "ring-fenced" area
of Block 14. Consequently, the Company and OBL consider the matter closed and
OBL has advised Petrobangla that no additional compensation is warranted.
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This filing contains certain forward-looking statements about Unocal's expected
earnings, production, commodity prices, capital spending, dry hole costs, future
operations and business negotiations. 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 2001 Annual Report on
Form 10-K and subsequent reports.
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-9-
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: July 30, 2002 By: /s/ JOE D. CECIL
--------------- -------------------------------
Joe D. Cecil
Vice President and Comptroller
-10-