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 22, 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.
Fourth Quarter and Full Year 2001 Preliminary Unaudited Results
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Unocal Corporation's preliminary results for the fourth quarter of 2001 were a
net loss of $29 million, or 12 cents per share (diluted). This compared to net
earnings of $173 million, or 70 cents per share (diluted), for the fourth
quarter of 2000.
For the Three Months For the Twelve Months
Ended December 31, Ended December 31,
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Millions of dollars 2001 2000 2001 2000
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Earnings (loss) from continuing operations $ (30) $ 173 $ 599 $ 723
Earnings from discontinued operations 1 - 17 37
Cumulative effect of accounting change - - (1) -
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Net earnings (loss) $ (29) $ 173 $ 615 $ 760
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Continuing operations resulted in a loss of $30 million, or 13 cents per share
(diluted), in the fourth quarter of 2001 compared to $173 million, or 70 cents
per share (diluted), for the same period a year ago. The decrease was primarily
due to lower prices for natural gas and liquids (crude oil, condensate and
natural gas liquids). The Company's worldwide average natural gas price was
$2.42 per thousand cubic feet (mcf) in the fourth quarter of 2001, which was a
decrease of $1.34 per mcf, or 36 percent, from the same period a year ago. In
the fourth quarter of 2001, the Company's worldwide average liquids price was
$17.90 per barrel in the fourth quarter of 2001, which was a decrease of $10.22
per barrel, or 36 percent, from the same period a year ago. The fourth quarter
of 2001 was also negatively impacted by an $86 million non-cash after-tax charge
for impairment of certain Gulf of Mexico shelf properties, due principally to
lower commodity prices. The fourth quarter of 2001 also included a $17 million
after-tax gain from the sale of a Gulf of Mexico production property. In
addition, the fourth quarter of 2001 benefited from $18 million in after-tax
earnings related to participation payments from the Company's former
agricultural products business and the Company's former oil and gas operations
in California and $15 million after-tax reduction in executive compensation
expense. The fourth quarter of 2000 included a $33 million after-tax charge to
write-down the Company's investment in the Questa, New Mexico, molybdenum mining
operation and $26 million in charges covering deferred income tax adjustments
and a provision for prior years income tax matters. In addition, earnings from
continuing operations in the fourth quarter of 2001 and 2000 included $24
million and $28 million, respectively, in after-tax provisions for litigation
and environmental matters.
Earnings from discontinued operations were $1 million in the fourth quarter of
2001, while there were no earnings from discontinued operations in the fourth
quarter of 2000. The $1 million after-tax benefit was related to the 1997 sale
of the Company's former West Coast refining, marketing and transportation
assets. The sales agreement covers price differences between California Air
Resources Board Phase 2 gasoline and conventional gasoline. The maximum
potential payments under this sales agreement are capped at $100 million and
extend to 2003. To date, the Company has earned approximately $27 million
(pre-tax) related to the agreement, all of which was recorded in 2001.
For the full year 2001, the Company's preliminary net earnings were $615
million, or $2.50 per share (diluted), with $599 million from continuing
operations, $17 million from discontinued operations, and a loss of $1 million
from the cumulative effect of an accounting change. This compared to $760
million, or $3.08 per share (diluted), for the same period a year ago, with $723
million from continuing operations and $37 million from discontinued operations.
-1-
Earnings from continuing operations in 2001 totaled $599 million, which was a
decrease of $124 million from a year ago. This decrease was
primarily due to lower worldwide average liquids prices and the fourth quarter
$86 million after-tax impairment charge. Higher worldwide average natural gas
prices and higher natural gas production partially offset these two negative
factors. The Company's worldwide average liquids price was $22.31 per barrel in
2001, which was a decrease of $3.79 per barrel, or 15 percent, from a year ago.
In 2001, the Company's worldwide average natural gas price was $3.25 per mcf,
which was an increase of 29 cents per mcf, or 10 percent, from a year ago. The
Company's worldwide natural gas production increased by 9 percent from a year
ago, primarily due to higher natural gas production from the U.S. Lower 48 and
Far East operations. The full year 2001 results also benefited from the $17
million after-tax gain from the sale of a Gulf of Mexico production property and
from a $10 million after-tax gain in mark-to-market accruals for non-hedge
commodity derivatives. The results in 2000 included a $55 million after-tax
benefit from payments received for infringement of one of the Company's five
reformulated gasoline patents during a five-month period in 1996, a $42 million
after-tax gain from the Pure Resources, Inc. (Pure) transaction and a $21
million after-tax gain related to an insurance recovery. These gains in 2000
were offset by $48 million in after-tax losses related to the mark-to-market
accruals for non-hedge commodity derivatives, the $33 million after-tax charge
to write-down the Company's investment in the Questa, New Mexico molybdenum
mining operation and $11 million after-tax in restructuring costs. In addition,
earnings from continuing operations in 2001 and 2000 included $95 million and
$99 million, respectively, in after-tax provisions for litigation and
environmental matters.
Earnings from discontinued operations were $17 million, or 7 cents per share
(diluted), in 2001 compared to $37 million, or 15 cents per share (diluted), in
2000. The 2001 amount related to the Company's sale of its former West Coast
refining, marketing and transportation assets. The 2000 amount reflected the
gain on disposal of the Company's former agricultural products business, which
was sold in late 2000.
In 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".
Total revenues from continuing operations for the fourth quarter of 2001 were
$1.3 billion, compared with $2.8 billion for the fourth quarter of 2000. Total
revenues from continuing operations for the full year of 2001 were $6.8 billion,
compared with $9.2 billion for the full year of 2000. The lower 2001 revenues
primarily reflected reduced crude oil trading activity by the Company's Trade
segment, as well as lower commodity prices.
Capital expenditures, excluding major acquisitions, for the fourth quarter of
2001 were $473 million, compared with $430 million for the fourth quarter of
2000. In the fourth quarter of 2001, the Company's major acquisitions included
$113 million to acquire a portion of Forest Oil Corporation's interests in
certain Gulf of Mexico shelf properties, while the fourth quarter of 2000 major
acquisitions included $157 million to acquire additional interests in the
Makassar Strait and Rapak production-sharing contract areas in Indonesia.
Capital expenditures, excluding major acquisitions, for the full year of 2001
were $1.73 billion, compared with $1.3 billion for full year of 2000. Major
acquisitions in 2001 included Pure's acquisition of properties from
International Paper Company for $266 million and its cash outlay of $171
million for the acquisition of all the shares of Hallwood Energy Corporation. In
2001, major acquisitions also included a $93 million cash outlay made by the
Company's Northrock Resources Ltd. (Northrock) subsidiary to acquire all the
shares of Tethys Energy Inc. and the aforementioned $113 million acquisition
from Forest Oil. Major acquisitions in 2000 included the aforementioned $157
million and $161 million for the acquisition of the remaining Northrock common
shares.
-2-
The Company's total debt, including current maturities, at the end of 2001 was
$2.91 billion, compared with $2.51 billion at the end of 2000. The debt-to-total
capitalization ratio was 44 percent at the end of 2001 remaining unchanged from
year-end 2000.
OPERATING HIGHLIGHTS
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Effective with the first quarter of 2001, the Company began reporting all
production pursuant to production sharing contracts on the net-economic
interests basis, which excludes host country shares. In previous reporting,
production had included host country shares in Indonesia and the Democratic
Republic of Congo. The Company also began reporting natural gas production on a
dry basis, with natural gas liquids now included with crude oil and condensate
production volumes. The production and price data for 2000 in the table on the
following page reflect these reclassifications.
-3-
OPERATING HIGHLIGHTS
(UNAUDITED)
For the Three Months For the Twelve Months
Ended December 31, Ended December 31,
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2001 2000 2001 2000
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North America Net Daily Production
Crude oil, condensate and natural gas liquids (thousand barrels)
Lower 48 (a) (b) 59 52 59 52
Alaska 26 25 25 26
Canada 19 16 16 17
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Total crude oil, condensate and natural gas liquids 104 93 100 95
Natural gas - dry basis (million cubic feet)
Lower 48 (a) (b) 860 840 905 764
Alaska 101 87 103 125
Canada 89 105 101 98
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Total natural gas 1,050 1,032 1,109 987
North America Average Prices (c)
Crude oil, condensate and natural gas liquids (per barrel)
Lower 48 $ 18.69 $ 29.69 $ 23.28 $ 27.20
Alaska $ 16.80 $ 28.02 $ 20.74 $ 24.93
Canada $ 13.49 $ 22.55 $ 18.53 $ 22.46
Average $ 17.21 $ 27.97 $ 21.83 $ 25.75
Natural gas (per mcf)
Lower 48 $ 2.50 $ 5.27 $ 4.22 $ 3.93
Alaska $ 1.57 $ 1.20 $ 1.37 $ 1.20
Canada $ 2.37 $ 3.20 $ 3.17 $ 2.30
Average $ 2.40 $ 4.69 $ 3.84 $ 3.40
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International Net Daily Production
Crude oil, condensate and natural gas liquids (thousand barrels)
Far East 57 50 51 47
Other (a) 19 17 19 18
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Total crude oil, condensate and natural gas liquids 76 67 70 65
Natural gas - dry basis (million cubic feet)
Far East 782 799 829 799
Other (a) 69 56 65 57
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Total natural gas 851 855 894 856
International Average Prices (c)
Crude oil, condensate and natural gas liquids (per barrel)
Far East $ 18.68 $ 28.16 $ 22.50 $ 26.17
Other $ 19.11 $ 29.08 $ 24.15 $ 27.84
Average $ 18.80 $ 28.34 $ 22.97 $ 26.61
Natural gas (per mcf)
Far East $ 2.45 $ 2.68 $ 2.52 $ 2.46
Other $ 2.43 $ 2.86 $ 2.75 $ 2.81
Average $ 2.45 $ 2.69 $ 2.54 $ 2.48
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Worldwide Net Daily Production (a) (b)
Crude oil, condensate and NGLs (thousand barrels) 180 160 170 160
Natural gas - dry basis (million cubic feet) 1,901 1,887 2,003 1,843
Barrels oil equivalent (thousands) 497 475 504 468
Worldwide Average Prices (c)
Crude oil, condensate and NGLs (per barrel) $17.90 $ 28.12 $ 22.31 $ 26.10
Natural gas (per mcf) $ 2.42 $ 3.76 $ 3.25 $ 2.96
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(a) Production includes proportional shares of production of equity investees.
(b) Includes minority interest shares of :
Crude oil , condensate and NGLs 9 8 9 7
Natural gas 104 77 102 69
Barrels oil equivalent 26 21 26 19
(c) Average prices include hedging gains and losses but exclude gains or losses
on derivative positions not accounted for as hedges, the ineffective
portion of hedges and other Trade margins.
-4-
2001 Reserve Replacement and FD&A Results
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The Company replaced 222 percent of its worldwide crude oil and natural gas
production during 2001 with new proved reserves. At year-end 2001, Unocal's
preliminary estimate of worldwide proved reserves totaled 1.81 billion
barrels-of-oil-equivalent (BOE), up 15 percent from 1.58 billion BOE at year-end
2000.
The Company booked its first reserves from the Mad Dog field, a new deepwater
development in the Gulf of Mexico, and added to its reserves in Azerbaijan,
Thailand, Indonesia, the Gulf of Mexico region, onshore Texas and Alaska through
the drillbit.
During 2001, the Company added reserves of 241 million BOE from discoveries and
extensions and improved recovery. Reserve acquisitions onshore Texas, on the
Gulf of Mexico shelf, and in Brazil and Canada totaled 113 million BOE. The
Company also made net upward revisions of 80 million BOE because of price
effects and reservoir performance. Because of cost-recovery provisions in
certain production-sharing contracts, the Company's reserves increase when
prices decline and decrease when prices increase. Production of 193 million BOE
and the sale of 5 million BOE partially offset the reserve increases.
For the year, the Company's preliminary estimated worldwide finding, development
and acquisition (FD&A) costs for new reserves were $6.18 per BOE.
Details of estimated proved reserves and finding, development and acquisition
costs will be published in the Company's 2001 Annual Report on Form 10-K in
March 2002.
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Unocal preliminary estimated proved reserves of
crude oil and natural gas (MMBOE)
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As of December 31, 2000 1,578
Discoveries and extensions 228
Improved recovery 13
Revisions 80
Purchases 113
Sales (5)
Production (193)
As of December 31, 2001 1,814
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Unocal's reserves reflect a change in the reporting method for reserves and
production in Indonesia and the Democratic Republic of Congo that was initiated
in 2001. All production-sharing contracts are now reported on the economic
interest method, which excludes host-country shares. The year-end 2000 reserves
have been reclassified to reflect this change. The year-end 2000 and 2001
reserves include amounts attributable to minority interests in consolidated
subsidiaries of 69 MMBOE and 97 MMBOE, respectively.
-5-
First Quarter and Full Year 2002 Outlook
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The Company expects its after-tax earnings (excluding special items) per share
to be between $1.10 to $1.20 for 2002. The Company expects net worldwide daily
production for 2002 to average between 510,000 and 520,000
barrels-of-oil-equivalent (BOE) per day. This compares with the Company's prior
disclosed forecast of 535,000 BOE per day. The reduction is primarily due to
faster than expected declines from the Muni field on Ship Shoal 295 in the Gulf
of Mexico and an expected reduction in capital spending in 2002 for short-term
production projects in light of current commodity price levels. The Company has
made slight revisions to its long- term production forecast but still projects a
6 percent annual growth rate through 2004.
Due to weakness in commodity prices, especially in NYMEX natural gas, and the
Company's desire to maintain a strong balance sheet, the Company is reducing its
expected capital spending by $100 to $150 million from the previously announced
$1.7 billion plan. The Company is prepared to make additional cuts if the
commodity price environment weakens further.
The Company intends to focus on longer-term exploration and development
activities and high-value, long-term development projects and shift its
exploration focus on the Gulf of Mexico shelf to deeper, more subtle plays, with
significantly higher resource potential and where it has significant competitive
advantages.
The Company plans to drill 8 to 10 net deep shelf exploration wildcats in 2002,
with activity increasing in the second half of the year. The capital cuts are
mainly focused on development and exploitation activities in North America that
would yield near-term production increases. The Company has the flexibility to
invest additional capital if prices recover or new opportunities arise in areas
such as Thailand, which are not subject to NYMEX pricing.
The forecast for full-year 2002 earnings assumes average NYMEX benchmark prices
of $20.00 per barrel of crude oil and $3.00 per million British thermal units
(mmBtus) for North America natural gas. Earnings are expected to change 15 cents
per share for every $1 change in the Company's average worldwide realized price
for crude oil and 9 cents per share for every 10-cent change in the Company's
average realized North America natural gas price. The forecast also assumes
pre-tax dry hole costs of $130 to $140 million (62% to 59% success rate).
Earnings are expected to change 8 cents per share for each 10- percent change in
the overall success rate of the Company's exploration drilling program.
The Company expects after-tax earnings (excluding special items) per share of 10
cents to 15 cents for the first quarter of 2002. The forecast assumes average
NYMEX benchmark prices of $19.35 per barrel of crude oil and $2.25 per mmBtus
for North America gas. In the first quarter of 2002, the Company expects net
worldwide production to average between 490,000 and 500,000 BOE per day.
-6-
Alaska Discovery
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The Company made a discovery of a new natural gas reservoir on Alaska's Kenai
Peninsula. The Grassim Oskolkoff #1 (GO#1) well, the first exploration well
drilled under a joint operating agreement between the Company and Marathon Oil
Company (Marathon) in the Ninilchik Exploration Unit, indicated significant
natural gas accumulations. The GO#1 well is located 35 miles south of Kenai,
Alaska, on the Kenai Peninsula. A 39-foot interval in the Miocene formation
yielded restricted flow rates of up to 11.2 million cubic feet of gas per day.
The zone tested was at 9,822 feet. The well was drilled to a total depth of
11,600 feet. Exploration efforts also continue at several other wells in the
unit. Unocal holds a 40 percent working interest in the well and the 25,000-acre
Ninilchik Exploratory Unit. Marathon is operator and holds the remaining
interest.
The Company also began a separate three-well exploration program on the southern
Kenai Peninsula, and it anticipates completing this initial program by May 2002.
The Company has acquired a total position in excess of 80,000 net acres. The
Company expects to have completed and tested eight wells on the trend -- five
wells in the Ninilchik Unit, and three wells on the other Unocal prospects by
the end of 2002.
Based on program results, the two companies expect to have sufficient gas
resources to support construction of the proposed Kenai-Kachemak pipeline. The
two companies formed the Kenai Kachemak Pipeline LLC to develop a natural gas
pipeline that would connect the new producing area with the existing south
central Alaska pipeline system. Upon completion of the pipeline, newly
discovered resources are expected to serve commercial and utility markets in
south central Alaska. First production is anticipated to occur in late 2003.
The Company has signed a contract to sell up to 450 billion cubic feet of
natural gas to ENSTAR Natural Gas Company beginning in January 2004. ENSTAR
distributes natural gas to Anchorage, the Matanuska-Susitna Valley, and the
Kenai Peninsula. The Regulatory Commission of Alaska approved the Unocal-ENSTAR
gas contract in December 2001.
Trident Appraisal Well
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The Company completed the first appraisal well at the Trident deepwater Gulf of
Mexico discovery in Alaminos Canyon Block 903. The well is located approximately
one and a half miles northwest of the original discovery and was drilled to a
total depth of 20,500 feet in 9,727 feet of water. The objectives of the
appraisal well were to test the downdip extent of the productive intervals found
in the Trident discovery well and to gather critical information about reservoir
quality.
The appraisal well encountered the same hydrocarbon-bearing intervals found in
the discovery well, a favorable indication of lateral reservoir continuity. The
well penetrated oil-water transition zones. In one of the key findings,
preliminary analysis of the core data confirms the presence of good quality
reservoir rock in the key uppermost pay zones in the structure. Tests conducted
on oil samples taken from the appraisal well indicate the same fluid quality of
40(degree) API gravity found in the discovery well, which is an important factor
in future development economics.
The Company may drill a second appraisal well at Trident as early as the second
half of 2002 and plans to put significant effort into analyzing deepwater
development options, including the likely use of Floating Production Storage and
Off-Loading (FPSO) technology.
The appraisal well was drilled in 68 days at a gross cost of $32 million. The
Company is the operator and has a 59.5 percent working interest in the prospect.
-7-
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Forward-looking statements and estimates regarding projected earnings, commodity
prices, dry hole costs, production levels, capital expenditures and other
drilling activities, in this filing are based on assumptions about operational,
market, competitive, regulatory, environmental, political and other
considerations. Actual results could differ materially as a result of factors
discussed in Unocal 's 2000 Annual Report on Form 10-K and subsequent reports.
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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: January 31, 2002 By: /s/ JOE D. CECIL
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Joe D. Cecil
Vice President and Comptroller
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