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) July 29, 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.
Second Quarter 2003 Results
---------------------------
Unocal Corporation's net earnings were $177 million, or 68 cents per share
(diluted), in the second quarter of 2003 compared with $114 million, or 46 cents
per share (diluted), in the second quarter of 2002. In the second quarter of
2003, net earnings included $8 million, or 3 cents per share (diluted),
attributable to earnings from discontinued operations compared with $1 million
in the same period a year ago.
For the Three Months For the Six Months
Ended June 30, Ended June 30,
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Millions of dollars 2003 2002 2003 2002
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Earnings from continuing operations $ 169 $ 113 $ 386 $ 135
Earnings from discontinued operations 8 1 8 1
Cumulative effects of accounting changes - - (83) -
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Net earnings $ 177 $ 114 $ 311 $ 136
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Continuing Operations
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Second Quarter Results: Earnings from continuing operations increased by $56
million in the second quarter of 2003 compared to the same quarter a year ago,
primarily reflecting improved results from the Company's exploration and
production operations, due to higher worldwide natural gas and liquids prices.
Higher worldwide commodity prices increased net earnings by approximately $90
million. The Company's worldwide average realized natural gas price, including a
loss of 7 cents per thousand cubic feet ("Mcf") from hedging activities, was
$3.53 per Mcf for the current quarter. This was an increase of 66 cents per Mcf,
or 23 percent, from the $2.87 per Mcf realized during the same period a year
ago. In the current quarter, the Company's worldwide average realized liquids
price was $25.36 per barrel ("Bbl"), which was an increase of $2.11 per Bbl, or
9 percent, from the same period a year ago. The Company's hedging program
lowered the average realized liquids price by 4 cents per Bbl in the current
quarter while the second quarter of the prior year included a loss of one cent
per Bbl from hedging activities.
In the current quarter, International production contributed approximately $29
million in higher earnings. The largest contributor to the higher International
production was Thailand, where oil-equivalent production was up 10 percent from
last year's second quarter. Crude oil and condensate production increased 29
percent, primarily because of de-bottlenecking production from the Yala-Plamuk
oil project and higher condensate production from the Pailin Phase 2 project.
Quarterly natural gas production increased 5 percent from last year due to
increased demand tied to higher electric power needs and reduced volumes from
other suppliers. The Company functions as the "swing producer" in Thailand,
providing above-contract minimum volumes when required to meet Thailand's needs.
The Company has routinely produced more than its contract minimums. Higher
production from Azerbaijan and Bangladesh also contributed to increased
International production. In addition, the Company recorded a $20 million
after-tax gain from the sale of its interest in Matador Petroleum Corporation
("Matador"), which was accounted for as an equity investment.
These positive variance factors were partially offset by lower North America
production and higher exploratory land provisions, which reduced net earnings by
approximately $25 million and $16 million, respectively, in the current quarter
compared with the same period a year ago. North America liquids daily production
averaged 84,000 Bbl in the current quarter, down from 96,000 Bbl per day in the
same period a year ago, while natural gas daily production averaged 805 million
cubic feet ("MMcf") in the current quarter, down from 935 MMcf per day in the
same period a year ago. Most of the production decline was due to natural
declines in existing fields in the Gulf of Mexico and the divestiture of various
properties in Canada, onshore U.S. and the Gulf of Mexico. The higher
exploratory land provisions are primarily a result of the anticipated
relinquishment of about 45 deepwater Gulf of Mexico blocks before their
expiration dates. In addition, higher pension related expenses also reduced net
earnings by approximately $10 million in the current quarter compared to the
same period a year ago.
-1-
The Company recorded a $17 million after-tax ($27 million pre-tax) restructuring
charge in the current quarter. The restructuring plan is aimed at strengthening
the Company's Lower 48 businesses, realigning its corporate staff and shared
resource groups, and improving its balance sheet. In the second quarter of 2002,
the Company recorded a $12 million after-tax ($19 million pre-tax) restructuring
charge in its Gulf Region business unit.
The second quarters of 2003 and 2002 both included after-tax gains of $2 million
and $4 million, respectively, in mark-to-market accruals and realized
gains/losses for non-hedge commodity derivatives recorded by the Company's
Northrock Resources Ltd. ("Northrock") subsidiary.
After-tax environmental and litigation expenses were $29 million in the current
quarter of 2003, compared with $15 million in the same period a year ago. In the
current quarter, the environmental expenses were primarily from recorded
provisions to the inactive Guadalupe oil field located on the central California
coast, which is part of the "Inactive or closed Company facilities" category,
and provisions for estimated cleanup costs for oil fields located in Michigan
and California that were formerly operated by the Company, which are part of the
"Company facilities sold with retained liabilities and former Company-operated
sites" category.
Six Months Results: Earnings from continuing operations were $386 million in the
first six months of 2003 compared to $135 million for the same period a year
ago. The increase was primarily due to higher worldwide natural gas and liquids
prices. Higher worldwide commodity prices increased net earnings by
approximately $310 million. The Company's worldwide average realized natural gas
price, including a loss of 17 cents per Mcf from hedging activities, was $3.71
per Mcf in the first six months of 2003. This was an increase of $1.03 per Mcf,
or 38 percent, from the $2.68 per Mcf, including a benefit of 6 cents per Mcf
from hedging activities, realized during the first six months of 2002. In the
first six months of 2003, the Company's worldwide average realized liquids price
was $27.54 per Bbl, which was an increase of $6.41 per Bbl, or 30 percent, from
the same period a year ago. The Company's hedging program lowered the average
realized liquids price by 26 cents per Bbl in the first six months of 2003 while
the first six months of 2002 included a gain of 2 cents per Bbl from hedging
activities. International production also contributed approximately $37 million
in higher earnings, primarily from the higher Thailand production. The first six
months of 2003 included the $20 million after-tax gain on the sale of the equity
interest in Matador and 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 subsidiary. The results in the prior year period
included a $12 million after-tax impairment in Alaska.
These positive variance factors were partially offset by lower North America
production, higher dry hole costs in the Gulf of Mexico, higher pension related
expenses and the higher exploratory land provisions, which reduced net earnings
by approximately $30 million, $24 million, $19 million and $16 million,
respectively, in the first six months of 2003 compared with the same period a
year ago. North America daily liquids production averaged 85,000 Bbl in the
first six months of 2003, down from 98,000 Bbl per day a year ago, while natural
gas daily production averaged 833 MMcf down from 934 MMcf for the six months
period a year ago. Most of the production decline was due to natural declines in
existing fields in the Gulf of Mexico and the divestiture of various properties
in Canada, onshore U.S. and the Gulf of Mexico.
After-tax environmental and litigation expenses were $46 million in the first
six months of 2003, compared with $38 million in the same period a year ago. In
addition to the second quarter provisions discussed above, the Company had
recorded provisions in the first quarter of 2003 for remediation projects at the
Company's former refinery in Beaumont, Texas, which is part of the "Inactive or
closed Company facilities" category.
The first six months of 2003 included the company-wide $17 million restructuring
charge, while the same period a year ago included a $12 million restructuring
charge for the Gulf Region business unit.
-2-
Cumulative Effects of Accounting Changes
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In the first quarter of 2003, the Company recorded a non-cash $83 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 ("SFAS") No. 143, "Accounting for Asset Retirement Obligations." The
Company also increased its accrued abandonment and restoration liabilities by
$268 million and increased its net properties by $138 million on the
consolidated balance sheet as a result of the adoption of SFAS No.143.
Revenues
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Revenues from continuing operations for the second quarter of 2003 were $1.62
billion compared with $1.37 billion for the same period a year ago. In the first
six months of 2003, total revenues from continuing operations were $3.41 billion
compared with $2.42 billion for the same period a year ago. The increases, in
both the quarter and six months amounts, primarily reflected higher crude oil
and natural gas prices.
Selected Costs and Other Deductions
-----------------------------------
Administrative and general expense in the second quarter included a $27 million
pretax charge as a result of the restructuring program announced in June that is
aimed at strengthening the Company's Lower 48 businesses, realigning its
corporate staff and shared resource groups, and improving its balance sheet. The
higher administrative and general expense category also reflected higher
pension-related expenses.
Exploration expense was higher in the second quarter primarily from land
provisions of $26 million pre-tax that were a result of the Company's
anticipated relinquishment of about 45 deepwater Gulf of Mexico blocks before
their expiration dates. This reflects the decision to focus the Company's
deepwater Gulf of Mexico land position on those OCS blocks that have the best
potential.
Financial Condition
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Cash flows from operating activities, including working capital and other
changes, was $1.09 billion in the first six months of 2003 compared with $626
million in the same period a year ago. The increase principally reflected the
effects of higher worldwide commodity prices.
Capital expenditures were $917 million for the first six months of 2003 compared
with $830 million in the same period a year ago.
Pre-tax proceeds from asset sales were $125 million in the second quarter, bring
the total for the six months of 2003 to $191 million. The current quarter
included various oil and gas property sales, as well as the sale of the
Company's interest in Matador which yielded $80 million in sale proceeds.
The Company's total consolidated debt, including current maturities, at June 30,
2003, was $3.0 billion, unchanged from the end of 2002. Cash and cash
equivalents on hand totaled $363 million at June 30, 2003, up from $168 million
at the end of 2002.
Proceeds from the sale of assets in 2003 will be used mainly to reduce debt and
other financings. As part of this program, the Company paid off the $252 million
limited partner interest in Spirit Energy 76 Development, L.P. in July. This
financing would have been reclassified from minority interests to debt in the
third quarter pursuant to Financial Accounting Standards Board Interpretation 46
("Consolidation of Variable Interest Entities").
Third Quarter 2003 and Full-Year 2003 Outlook
---------------------------------------------
The Company's current net worldwide daily production estimate for the third
quarter of 2003 is between 460,000 and 470,000 barrels-of-oil equivalent
("BOE"). Based on current market prices, the Company's net earnings for the
third 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 third
-3-
quarter of 2003, the Company has hedged 25 million MMBtu (million British
thermal units) of Lower 48 natural gas production and 2 million Bbl of Lower 48
crude oil, together representing approximately 45 percent of expected Lower 48
BOE production volume. Third quarter hedges include fixed price sales for
10 million MMBtu of natural gas at $5.87 per MMBtu and 1.1 million Bbl of crude
oil at $30.08 per Bbl. In addition, the Company has hedged 15 million MMBtu of
natural gas with pricing collars between $4.67 and $3.80 per MMBtu and 900,000
Bbl of crude oil with collars between $31.59 and $27.35 per Bbl. The Company
also forecasts third quarter pre-tax dry hole costs of $40 million to $50
million.
The Company currently estimates its full-year 2003 production to average between
470,000 to 480,000 BOE per day. This production forecast includes the associated
production loss of approximately 5,000 BOE per day from divestitures that the
Company has completed so far this year. This estimate also reflects the sale of
the Company's interest in Matador and a one-month delay in the start-up of the
West Seno field in Indonesia. The Company has additional property divestitures
pending or planned that if sold are expected to reduce production by 25,000 to
30,000 BOE per day. The Company's total actual production for the year could
also be impacted by cost recovery volume fluctuations under the Company's
various foreign PSCs due to changes in commodity prices, demand for natural gas
in Thailand, the rate of ramp-up in West Seno production and production and
exploration performance in the Gulf of Mexico. For the remainder of 2003, the
Company has hedged 49.5 million MMBtu of Lower 48 natural gas production and 2.8
million Bbl of Lower 48 crude oil, together representing approximately 40
percent of expected Lower 48 BOE production. The Company has fixed price sales
for 26 milion MMBtu of natural gas at $5.94 per MMBtu and 1.2 million Bbl of
crude oil at $30.08. In addition, the Company has hedged 23 million MMBtu of
natural gas with pricing collars between $4.65 and $3.79 per MMBtu and 1.6
million Bbl of crude oil with collars between $31.85 and $27.38 per Bbl. Based
on current prices, 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 pre-tax dry hole costs of $155 million
to $185 million and that pre-tax pension-related expenses will increase over
2002 by approximately $65 million to $70 million.
Cautionary Statement
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This filing contains certain forward-looking statements about Unocal's future
production rates, commodity prices, dry hole costs, divestitures, pension costs,
future operations, drilling plans, business transactions and other matters.
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, the
levels of the Company's oil and gas production, 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 disclosed on pages 56 to 68 of Unocal's 2002 Annual Report on Form
10-K.
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 31, 2003 By: /s/ JOE D. CECIL
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Joe D. Cecil
Vice President and Comptroller
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CONSOLIDATED EARNINGS (UNAUDITED) For the Three Months For the Six Months
Ended June 30, Ended June 30,
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Millions of dollars except
per share amounts 2003 2002 2003 2002
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Revenues
Sales and operating revenues $ 1,564 $ 1,361 $ 3,339 $ 2,396
Interest, dividends and
miscellaneous income (loss) 9 8 20 20
Gain (loss) on sales of assets 47 (1) 50 1
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Total revenues 1,620 1,368 3,409 2,417
Costs and other deductions
Crude oil, natural gas
and product purchases 536 428 1,182 723
Operating expense 325 324 619 623
Administrative and general expense 87 37 138 80
Depreciation, depletion and amortization 255 255 515 479
Asset impairments 3 21 3 21
Dry hole costs 10 13 81 41
Exploration expense 88 61 143 120
Interest expense 36 43 74 94
Property and other operating taxes 21 18 43 34
Distributions on convertible preferred
securities of subsidiary trust 8 8 16 16
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Total costs and other deductions 1,369 1,208 2,814 2,231
Earnings from equity investments 53 51 96 88
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Earnings from continuing operations before
income taxes and minority interests 304 211 691 274
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Income taxes 133 95 301 135
Minority interests 2 3 4 4
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Earnings from continuing operations 169 113 386 135
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Earnings from discontinued operations 8 1 8 1
Cumulative effects of accounting changes (a) - - (83) -
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Net earnings $ 177 $ 114 $ 311 $ 136
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Basic earnings per share of common stock (b)
Continuing operations $ 0.66 $ 0.46 $ 1.50 $ 0.55
Net earnings $ 0.69 $ 0.46 $ 1.21 $ 0.55
Diluted earnings per share of common stock (c)
Continuing operations $ 0.65 $ 0.46 $ 1.47 $ 0.55
Net earnings $ 0.68 $ 0.46 $ 1.20 $ 0.55
Cash dividends declared per share
of common stock $ 0.20 $ 0.20 $ 0.40 $ 0.40
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(a) Net of tax (benefit) $ - $ - $ (48) $ -
(b) Basic weighted average shares
outstanding (in thousands) 258,202 244,639 258,103 244,423
(c) Diluted weighted average shares
outstanding (in thousands) 272,108 245,865 271,907 245,531
-5-
CONDENSED CONSOLIDATED BALANCE SHEET (UNAUDITED) At June 30, At December 31,
Millions of dollars 2003 2002
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Assets
Cash and cash equivalents $ 363 $ 168
Other current assets - net 1,253 1,207
Investments and long-term receivables - net 1,074 1,044
Properties - net 8,327 7,879
Goodwill 129 122
Other assets 390 340
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Total assets $ 11,536 $ 10,760
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Liabilities and Stockholders' Equity
Current liabilities (a) $ 1,895 $ 1,632
Long-term debt and capital leases 2,744 3,002
Deferred income taxes 677 593
Accrued abandonment, restoration
and environmental liabilities 917 622
Other deferred credits and liabilities 860 816
Minority interests 276 275
Convertible preferred securities
of a subsidiary trust 522 522
Stockholders' equity 3,645 3,298
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Total liabilities and stockholders' equity $ 11,536 $ 10,760
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(a) Includes current portion of LTD of: 232 6
-6-
CONSOLIDATED CASH FLOWS (UNAUDITED) For the Six Months
Ended June 30,
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Millions of dollars 2003 2002
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Cash Flows from Operating Activities
Net earnings $ 311 $ 136
Adjustments to reconcile net earnings to
net cash provided by operating activities
Depreciation, depletion and amortization 515 479
Asset impairments 3 21
Dry hole costs 81 41
Amortization of exploratory leasehold costs 71 45
Deferred income taxes 41 (17)
Gain on sales of assets (pre-tax) (50) (1)
Gain on disposal of discontinued operations (pre-tax) (13) (2)
Cumulative effects of accounting changes 83 -
Other 110 (40)
Working capital and other changes related to operations (67) (36)
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Net cash provided by operating activities 1,085 626
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Cash Flows from Investing Activities
Capital expenditures (includes dry hole costs) (917) (830)
Proceeds from sales of assets 191 45
Proceeds from sale of discontinued operations - 2
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Net cash used in investing activities (726) (783)
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Cash Flows from Financing Activities
Long-term borrowings 79 440
Reduction of long-term debt
and capital lease obligations (143) (229)
Minority interests (3) (4)
Proceeds from issuance of common stock 10 19
Dividends paid on common stock (103) (98)
Other (4) -
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Net cash provided by (used in)
financing activities (164) 128
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Net increase (decrease) in cash and cash equivalents 195 (29)
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Cash and cash equivalents at beginning of year 168 190
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Cash and cash equivalents at end of period $ 363 $ 161
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OPERATING HIGHLIGHTS For the Three Months For the Six Months
Ended June 30, Ended June 30,
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2003 2002 2003 2002
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North America Net Daily Production
Liquids (thousand barrels)
U.S. Lower 48 (a) (b) 44 54 46 55
Alaska 23 25 22 25
Canada 17 17 17 18
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Total liquids 84 96 85 98
Natural gas - dry basis (million cubic feet)
U.S. Lower 48 (a) (b) 652 766 678 754
Alaska 67 77 64 89
Canada 86 92 91 91
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Total natural gas 805 935 833 934
North America Average Prices (excluding hedging activities) (c)
Liquids (per barrel)
U. S. Lower 48 $ 26.02 $ 23.49 $ 28.11 $ 20.95
Alaska $ 27.46 $ 24.74 $ 31.34 $ 21.99
Canada $ 23.52 $ 21.92 $ 26.05 $ 19.15
Average $ 25.93 $ 23.56 $ 28.48 $ 20.89
Natural gas (per mcf)
U. S. Lower 48 $ 5.01 $ 3.12 $ 5.66 $ 2.68
Alaska $ 1.20 $ 1.57 $ 1.20 $ 1.57
Canada $ 5.13 $ 3.03 $ 5.40 $ 2.54
Average $ 4.69 $ 2.98 $ 5.27 $ 2.55
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North America Average Prices (including hedging activities) (c)
Liquids (per barrel)
U. S. Lower 48 $ 25.84 $ 23.48 $ 27.22 $ 21.01
Alaska $ 27.46 $ 24.74 $ 31.34 $ 21.99
Canada $ 23.52 $ 21.92 $ 26.05 $ 19.15
Average $ 25.84 $ 23.56 $ 27.99 $ 20.92
Natural gas (per mcf)
U. S. Lower 48 $ 4.86 $ 3.12 $ 5.23 $ 2.80
Alaska $ 1.20 $ 1.57 $ 1.20 $ 1.57
Canada $ 4.79 $ 2.97 $ 5.07 $ 2.62
Average $ 4.53 $ 2.97 $ 4.89 $ 2.66
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(a) Includes proportional interests in production of equity investees.
(b) Includes minority interests of :
Liquids 1 9 1 9
Natural gas 11 98 10 98
Barrels oil equivalent 3 25 2 25
(c) Excludes gains/losses on derivative positions not accounted for as hedges
and ineffective portions of hedges.
-8-
OPERATING HIGHLIGHTS (CONTINUED) For the Three Months For the Six Months
Ended June 30, Ended June 30,
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2003 2002 2003 2002
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International Net Daily Production (d)
Liquids (thousand barrels)
Far East 59 54 57 53
Other (a) 20 20 21 20
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Total liquids 79 74 78 73
Natural gas - dry basis (million cubic feet)
Far East 911 883 890 852
Other (a) 89 79 100 78
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Total natural gas 1,000 962 990 930
International Average Prices (e)
Liquids (per barrel)
Far East $ 24.78 $ 22.50 $ 27.06 $ 20.95
Other $ 25.16 $ 23.91 $ 27.11 $ 23.03
Average $ 24.90 $ 22.84 $ 27.07 $ 21.43
Natural gas (per mcf)
Far East $ 2.74 $ 2.78 $ 2.75 $ 2.70
Other $ 2.89 $ 2.79 $ 2.86 $ 2.64
Average $ 2.76 $ 2.78 $ 2.76 $ 2.69
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Worldwide Net Daily Production (a) (b) (d)
Liquids (thousand barrels) 163 170 163 171
Natural gas-dry basis (million cubic feet) 1,805 1,897 1,823 1,864
Barrels oil equivalent (thousands) 463 486 467 482
Worldwide Average Prices (excluding hedging activities) (c)
Liquids (per barrel) $ 25.40 $ 23.26 $ 27.80 $ 21.11
Natural gas (per mcf) $ 3.60 $ 2.87 $ 3.88 $ 2.62
Worldwide Average Prices (including hedging activities) (c) (e)
Liquids (per barrel) $ 25.36 $ 23.25 $ 27.54 $ 21.13
Natural gas (per mcf) $ 3.53 $ 2.87 $ 3.71 $ 2.68
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(a) Includes proportional interests in production of equity investees.
(b) Includes minority interests of :
Liquids 1 9 1 9
Natural gas 11 98 10 98
Barrels oil equivalent 3 25 2 25
(c) Excludes gains/losses on derivative positions not accounted for as hedges
and ineffective portions of hedges.
(d) International production is presented utilizing
the economic interest method.
(e) International did not have any hedging activities.
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