8-K 1 u8k729b03.txt 2Q03 EARNINGS ITEM 5 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 ------------------------ UNOCAL CORPORATION -------------------------------------------------------------------------------- (Exact name of registrant as specified in its charter) Delaware -------------------------------------------------------------------------------- (State or Other Jurisdiction of Incorporation) 1-8483 95-3825062 -------------------------------------------------------------------------------- (Commission File Number) (I.R.S. Employer Identification No.) 2141 Rosecrans Avenue, Suite 4000, El Segundo, California 90245 -------------------------------------------------------------------------------- (Address of Principal Executive Offices) (Zip Code) (310) 726-7600 -------------------------------------------------------------------------------- (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, -------------------------------------------- Millions of dollars 2003 2002 2003 2002 -------------------------------------------------------------------------------- Earnings from continuing operations $ 169 $ 113 $ 386 $ 135 Earnings from discontinued operations 8 1 8 1 Cumulative effects of accounting changes - - (83) - -------------------------------------------------------------------------------- Net earnings $ 177 $ 114 $ 311 $ 136 ================================================================================
Continuing Operations --------------------- 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 ---------------------------------------- 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 -------- 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 ------------------- 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 -------------------- 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 ------------------ ------------------------------- Joe D. Cecil Vice President and Comptroller -4-
CONSOLIDATED EARNINGS (UNAUDITED) For the Three Months For the Six Months Ended June 30, Ended June 30, ------------------------------------------ Millions of dollars except per share amounts 2003 2002 2003 2002 -------------------------------------------------------------------------------- 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 -------------------------------------------------------------------------------- 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 -------------------------------------------------------------------------------- Total costs and other deductions 1,369 1,208 2,814 2,231 Earnings from equity investments 53 51 96 88 -------------------------------------------------------------------------------- Earnings from continuing operations before income taxes and minority interests 304 211 691 274 -------------------------------------------------------------------------------- Income taxes 133 95 301 135 Minority interests 2 3 4 4 -------------------------------------------------------------------------------- Earnings from continuing operations 169 113 386 135 -------------------------------------------------------------------------------- Earnings from discontinued operations 8 1 8 1 Cumulative effects of accounting changes (a) - - (83) - -------------------------------------------------------------------------------- Net earnings $ 177 $ 114 $ 311 $ 136 ================================================================================ 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 -------------------------------------------------------------------------------- (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
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CONDENSED CONSOLIDATED BALANCE SHEET (UNAUDITED) At June 30, At December 31, Millions of dollars 2003 2002 -------------------------------------------------------------------------------- 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 -------------------------------------------------------------------------------- Total assets $ 11,536 $ 10,760 ================================================================================ 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 -------------------------------------------------------------------------------- Total liabilities and stockholders' equity $ 11,536 $ 10,760 ================================================================================ (a) Includes current portion of LTD of: 232 6
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CONSOLIDATED CASH FLOWS (UNAUDITED) For the Six Months Ended June 30, --------------------------- Millions of dollars 2003 2002 -------------------------------------------------------------------------------- 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) -------------------------------------------------------------------------------- Net cash provided by operating activities 1,085 626 -------------------------------------------------------------------------------- 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 -------------------------------------------------------------------------------- Net cash used in investing activities (726) (783) -------------------------------------------------------------------------------- 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) - -------------------------------------------------------------------------------- Net cash provided by (used in) financing activities (164) 128 -------------------------------------------------------------------------------- Net increase (decrease) in cash and cash equivalents 195 (29) -------------------------------------------------------------------------------- Cash and cash equivalents at beginning of year 168 190 -------------------------------------------------------------------------------- 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, ----------------------------------------- 2003 2002 2003 2002 -------------------------------------------------------------------------------- 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 -------------------------------------------------------------------------------- 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 -------------------------------------------------------------------------------- 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 -------------------------------------------------------------------------------- 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 -------------------------------------------------------------------------------- (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.
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OPERATING HIGHLIGHTS (CONTINUED) For the Three Months For the Six Months Ended June 30, Ended June 30, ----------------------------------------- 2003 2002 2003 2002 -------------------------------------------------------------------------------- International Net Daily Production (d) Liquids (thousand barrels) Far East 59 54 57 53 Other (a) 20 20 21 20 -------------------------------------------------------------------------------- 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 -------------------------------------------------------------------------------- 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 -------------------------------------------------------------------------------- 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 -------------------------------------------------------------------------------- (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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