ITEM 3 - LEGAL PROCEEDINGS.
There is incorporated by reference: the information regarding environmental remediation reserves and possible additional remediation costs in notes 20 and 24 to the consolidated financial statements in Item 8 of this report; the discussion of such amounts in the Environmental Matters section of Management’s Discussion and Analysis in Item 7 of this report; and the information regarding certain litigation and claims, tax matters and other contingent liabilities in note 24 to the consolidated financial statements in Item 8 of this report. See also the information under “Patents” in Items 1 and 2-Business and Properties of this report regarding certain lawsuits and administrative proceedings involving the Company’s patents for cleaner-burning gasolines. Set forth below is information with respect to certain additional legal proceedings pending or threatened against the Company:
1. Since 1993, the Company, along with other shippers of Alaska North Slope (“ANS”) crude oil through the Trans-Alaska Pipeline System (“TAPS”), has been a party to proceedings pending jointly before the Federal Energy Regulatory Commission (“FERC”) and the Regulatory Commission of Alaska (“RCA”) relating to the “TAPS Quality Bank.” ANS crude oil comes from various fields, and has varying constituents and qualities. All crude oil is blended in the TAPS for transmission from the North Slope to the tanker port at Valdez, where shippers then take their respective volumes of the blended stream. The TAPS Quality Bank is a mechanism that provides for adjustments among the shippers based on their entitlements to the co-mingled stream due to the effect of the varying constituents and qualities on the relative values of the crude oils they each put through the pipeline. As a shipper of lower-quality crude oil, compared to that of the blended stream, the Company is generally required to pay an assessed sum into the Quality Bank for distribution to those shippers who placed higher-quality crude oil into TAPS.
In December 2000, the U.S. Court of Appeals for the District of Columbia Circuit reversed a decision by FERC relating to the methodology to be applied in calculating the valuation of the distillation components of the various crude oils shipped through TAPS. The court remanded the matter to FERC for further proceedings, including arguments by ExxonMobil Corporation and Tesoro Petroleum Corporation that the distillation methodology for valuing the crude oils is not just and reasonable and that a new, revised methodology, if and when adopted by FERC, should be made retroactive to 1993. A hearing before a FERC administrative law judge was concluded in June 2003. Post-hearing briefing was completed in November of 2003. The initial decision by the administrative law judge, anticipated in late April 2004, is subject to the FERC’s authority to change it. This will determine the value of certain cuts of the crude oil stream and will assess retroactive amounts as well as set the value of the cuts going forward. It is anticipated that the RCA will then adopt the FERC decision for intrastate transportation of ANS crude oil.
2. The Company has been named a defendant in two proceedings brought by private plaintiffs on behalf of the United States alleging underpayment of royalties since the mid-1980s on natural gas production from federal and Indian land leases in violation of the federal False Claims Act (“FCA”). The first action (United States, ex rel. Harrold E. (Gene) Wright v. Amerada Hess Corp., et al., in the U.S. District Court for the Eastern District of Texas, Lufkin Division) was filed in 1996 against the Company and 130 other energy industry companies and seeks damages collectively from all defendants of $3 billion, which, to the extent awarded, would be trebled pursuant to the FCA. In 2000, the U.S. Department of Justice (“DOJ”) intervened in the lawsuit against four of the defendants, but has not intervened against the remaining defendants, including the Company.
The second action (United States, ex rel. Jack Grynberg v. Unocal, in the U.S. District Court for the District of Wyoming) was filed in 1997, as one of 77 separate cases filed by the plaintiff, and seeks damages of approximately $200 million from the Company, which, to the extent awarded, would be trebled pursuant to the FCA. In 1999, the DOJ notified the courts in the Grynberg litigation of its election not to intervene in these actions.
A decision by the DOJ to intervene against a defendant sued under the FCA normally is an indication that the DOJ has investigated and concluded that there is some basis in fact to support the private plaintiff’s claim against that particular defendant. Conversely, a decision not to intervene is normally an indication that the DOJ has found no basis in fact to support the private plaintiff’s assertions. The Company has cooperated fully with the DOJ in connection with its investigations in both the Wright and Grynberg cases. To date, the Company has received no indication from the DOJ that it contemplates intervening against the Company in either lawsuit.
The Wright and Grynberg cases were consolidated by the Judicial Panel on Multi-District Litigation as MDL Docket No. 1293 and subsequently transferred for pre-trial proceedings to the U.S. District Court for the District of Wyoming. In December 2003, the Wright case was remanded to the Eastern District of Texas, Texarkana Division. The Grynberg v. Unocal lawsuit remains consolidated in MDL-1293 with the 76 other Grynberg cases. Limited discovery has been allowed in both proceedings to address threshold jurisdictional issues concerning whether Messrs. Grynberg and Wright have standing as proper qui tam relators. Motions to dismiss for lack of subject matter jurisdiction will be presented in the coming months to the U.S. District Courts in Wyoming and Texarkana. All other aspects of these cases have been stayed pending resolution of the jurisdictional issues. The parties in the Wright case have recently been directed by the Court to formulate a scheduling order to govern further case proceedings. The Company is vigorously defending both cases and believes that their outcomes are not likely to have a material adverse effect on the Company’s financial condition, liquidity or results of operations.
3. The Company is a defendant in lawsuits by anonymous residents and former residents of the Tenasserim region of Myanmar. The lawsuits were initially filed in 1996 in the U.S. District Court for the Central District of California (John Doe I, et al. v. Unocal Corp., et al., Case No. CV 96-6959-RWSL; and John Roe III, et al. v. Unocal, Inc. [sic], et al., Case No. CV 96-6112-RWSL). The plaintiffs alleged that the Company was liable for alleged acts of mistreatment and forced labor by the government of Myanmar allegedly in connection with the construction of the Yadana natural gas pipeline, which transports natural gas from fields in the Andaman Sea across Myanmar to its border with Thailand.
The complaints contained numerous counts and alleged violations of several U.S. and California laws and U.S. treaties. The plaintiffs sought compensatory and punitive damages on behalf of the named plaintiffs, as well as disgorgement of profits.
In 2000, the District Court granted the Company’s motions for summary judgment in both actions, ordered the federal law claims dismissed and, after declining to exercise jurisdiction over the pendant state law claims, ordered them dismissed without prejudice.
The plaintiffs in both actions appealed the final judgments to the U.S. Court of Appeals for the Ninth Circuit (Case Nos. 00-56603 and 00-56628, respectively). In 2002, a three-judge panel of the Circuit Court issued an opinion that reversed in part and affirmed in part the District Court’s ruling and remanded the case for further proceedings in the District Court. The panel held that, if proved at trial, the alleged conduct of the Myanmar military, consisting of alleged forced labor and certain alleged related violence, would constitute violations of international law actionable under the Alien Tort Claims Act (28 U.S.C. § 1350). The panel further held that international law concerning the standard for “aiding and abetting” liability applies to the plaintiffs’ claims against the Company and found sufficient disputed facts to warrant a trial. Subsequently, the Company was granted a rehearing by an 11-judge “en banc” panel of the Circuit Court in June 2003. Because of a pending U.S. Supreme Court case raising similar issues (Sosa v. Alvarez-Machian), the Circuit Court will not issue a decision until that case is decided.
In 2000, following the dismissal of their claims by the federal court, the plaintiffs filed actions against the Company in the Superior Court of the State of California for the County of Los Angeles, Central District (John Doe I, et al. v. Unocal Corp., et al., No. BC237980; and John Roe III, et al. v. Unocal Corporation, et al., No. BC237679). The complaints allege that, by virtue of the Company’s participation in the Yadana project, it is liable under California law for alleged acts of mistreatment and forced labor by the government of Myanmar. The complaints contain numerous counts alleging various violations by the defendants of the constitution, statutes and common law of California. The plaintiffs seek compensatory and punitive damages on behalf of the named plaintiffs, as well as injunctive relief, disgorgement of profits and other equitable relief.
In 2002, the state court dismissed all of the plaintiffs’ tort causes of action that were premised on alleged intentional or negligent actions of the Company. The remaining causes of action in both state cases are all premised on whether the Company should be held vicariously liable to the individual plaintiffs for the alleged wrongful acts of the Myanmar military. In December 2003 a bifurcated trial commenced on whether the plaintiffs could proceed against the Company and/or Union Oil Company of California as the alter-egos of the subsidiaries that actually hold the interest in the Yadana pipeline. Following trial, the court held that Unocal and Union Oil were not the alter-egos of the subsidiaries. The Company anticipates further proceedings over the next several months as to whether this decision effectively ends the state court proceedings.
The Company believes that the outcomes of the federal and state cases are not likely to have a material adverse effect on the Company’s financial condition or liquidity or, based on management’s current assessment of the cases, the Company’s results of operations.
4. In June 2002, a lawsuit was filed against the Company by Agrium Inc., a Canadian corporation, and Agrium U.S. Inc., its U. S. subsidiary, in the Superior Court of the State of California for the County of Los Angeles (Agrium U.S. Inc. and Agrium Inc. v. Union Oil Company of California, Case No. BC275407) (the “Agrium Claim”). Simultaneously, the Company filed suit against the Agrium entities (“Agrium”) in the U.S. District Court for the Central District of California (Union Oil Company of California v. Agrium, Inc., Case No. 02-04518 NM) (the “Company Claim”). The Company subsequently removed the Agrium Claim to the U.S. District Court for the Central District of California (Case No. 02-04769 NM). The federal court has since remanded the Agrium Claim to the California Superior Court. In addition, the Company has initiated arbitration concerning the Gas Purchase and Sale Agreement (“GPSA”) between the Company and Agrium U.S. Inc. (AAA Case No. 70 198 00539 02) (the “Arbitration”).
The Agrium Claim alleges numerous causes of action relating to Agrium’s 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 the GPSA. Agrium alleges that the Company misrepresented the amount of natural gas reserves available for sale to the plant as of the closing of the transaction and that the Company has failed to develop additional natural gas 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 in the Purchase and Sale Agreement for the plant (the “PSA”) 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.
In September 2002, Agrium amended its complaint to add allegations that the Company breached certain conditions of the September 2000 closing, breached certain indemnification obligations, and violated the pertinent health and safety code. Agrium also asked for recission of the sale of the fertilizer plant, in addition, or as an alternative, to money damages. In addition, Agrium seeks a declaration by the arbitral panel that has been convened (see below) that natural gas from Unocal’s Ninilchik, Happy Valley fields “or elsewhere” should be delivered to the plant to meet Unocal’s alleged obligations under the GPSA.
In the Company Claim, 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 $17 million plus interest accrued subsequent to May 2002. Unocal is also seeking over $900,000 in reliability bonuses due under the GPSA and reimbursement of over $5 million in royalties paid to the State of Alaska.
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.
On July 16, 2003, the court approved an agreed stipulation between the parties to submit all issues under the GPSA to arbitration. The arbitration proceedings are scheduled to commence May 24, 2004. Discovery is now proceeding.
5. In June, 2000, the City of Santa Monica, California (the “City”) sued Shell Oil Company and other oil companies, including the Company, for contamination with methyl tertiary butyl ether (“MTBE”) and a related chemical, tertiary butyl alcohol (“TBA”), of water pumped from the City’s Charnock wellfield (City of Santa Monica v. Shell Oil Company et al. California Superior Court, Orange County, Case No. 01CC04331). The City alleged that releases from sites owned by Shell, ChevronTexaco Corporation and ExxonMobil Corporation caused the wellfield to be shut down, and that releases from sites owned by Unocal subsequently impacted the wellfield. The City also alleged Unocal was liable under a products liability theory for gasoline it manufactured or sold that was ultimately distributed to area facilities operated by others. The Company was also subject to potential contractual liability for contamination from former facilities related to our gasoline marketing business sold in 1997. In 2001, Shell filed a cross-complaint against the Company and other oil companies, seeking the recovery of the funds it has expended to respond to the contamination.
The parties reached a settlement on all matters relating to the lawsuit, which was approved by the court as a “good faith” settlement without objection on December 19, 2003. Unocal’s portion of the settlement required payment to the plaintiff of $5 million, which was paid in February 2004.
The Company has recently been named as a defendant in numerous other MTBE lawsuits brought by water companies throughout the country. These cases typically involve numerous other defendants, and do not allege specific facts which would make Unocal responsible for the claims asserted. Many of these cases appear to have no basis for the imposition of liability against the Company because the Company did not operate service stations or market gasoline in the geographic areas involved in the lawsuits. Many also appear to involve uncertain threats to water supplies rather than actual injury. Some of these cases may be subject to contractual indemnification by third parties once the allegations are clarified. Most have been removed to federal court, and may or may not be remanded to state court for discovery and trial. It is too early to determine what, if any, liability Unocal may have in these cases.
6. In March 2003, the Company received a letter from Nuevo Energy Company regarding a contingent payment for the year 2002 owed by Nuevo to the Company under the terms of the 1996 Asset Purchase Agreement pursuant to which Nuevo purchased substantially all of the Company’s operating California oil and gas properties. Notwithstanding that Nuevo had notified the Company in January 2003 of its estimate of the payment for 2002, Nuevo now claims that the long-standing calculation methodology for this payment was incorrect, that no payment should be due for 2002, and that the payment made for 2001 should be refunded. The Company disputes Nuevo’s new position.
On June 30, 2003, Nuevo filed suit against Unocal in the U.S. District Court for the Central District of California, Case No. 03-4664 (RCx). Nuevo seeks $10.8 million, the amount Nuevo alleges it paid Unocal in error. Nuevo also seeks a declaratory judgment regarding its right to take deductions in calculating the contingent payment in the future. Unocal has counterclaimed, seeking in excess of $16 million for amounts owed from 2002 under the contingent payment agreement and for a declaratory judgment regarding the rights and relations of Unocal and Nuevo under that agreement. The case is scheduled to go to trial on May 11, 2004.
7. In July 2002, the Company’s subsidiary Unocal Bangladesh Blocks Thirteen and Fourteen, Ltd. (“Unocal Blocks 13 and 14 Ltd.”) received a letter from the Bangladesh Oil, Gas & Mineral Corporation (“Petrobangla”) claiming, on behalf of the Bangladesh government and Petrobangla, compensation allegedly due in the amount of $685 million for 246 BCF of recoverable natural gas allegedly “lost and damaged” in a 1997 blowout and ensuing fire during the drilling by Occidental Petroleum Corporation (known at that time in Bangladesh as Occidental of Bangladesh Ltd.) (“OBL”), as operator, of the Moulavi Bazar #1 (“MB #1”) exploration well on the Blocks 13 and 14 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 contractor’s 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 1998 Supplemental Agreement to the PSC (the “Supplemental Agreement”), 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 (“Unocal Bangladesh”)) of entitlement to the recovery of costs incurred in the drilling of the MB #1 and 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 present or development is not feasible, from other commercial fields in the Moulavi Bazar “ring-fenced” area of Block 14. Consequently, the Company and OBL consider the matter closed and Unocal Blocks 13 and 14 Ltd. has advised Petrobangla that no additional compensation is warranted. By Writ Petition Affidavit dated March 24, 2003, a concerned citizen filed suit in the Bangladesh lower court (Alam v. Bangladesh, Petrobangla, Department of Environment, and Unocal Bangladesh, Ltd., Supreme Court of Bangladesh, High Court Division, Writ Petition No. 2461 of 2003) on the basis of the MB #1 blowout. The Company was notified of the suit on May 26, 2003 when it received the court’s order to show cause why the Supplemental Agreement should not be declared illegal and cancelled on account of its having been executed without lawful authority, and why Unocal Bangladesh should not be directed to stop exploration until it compensates for the MB#1 blowout. No
hearing is currently scheduled on the matter, and the Company believes the action is not well founded.
Certain Environmental Matters Involving Civil Penalties
On February 13, 2004, the U.S. Coast Guard provided the Company, as operator, with a draft complaint regarding a discharge of oil-based drilling mud from an injection of drilling mud and cuttings into the annulus of a well on the King Salmon Platform. The Coast Guard has agreed in principle to settle the matter. The Company anticipates that the Alaska Department of Environmental Conservation (“DEC”) will also seek civil penalties for the discharge, but no complaint has been filed or provided to the Company. The Company estimates that its share of the aggregate fine for the discharge from both the Coast Guard and the Alaska DEC may be over $100,000.
ITEM 4
ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS: None.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following is a list of the executive officers as of February 27, 2004, showing their ages, present positions and their business experience during the past five or more years. The bylaws of the Company provide that each executive officer shall hold office until the annual organizational meeting of the Board of Directors, to be held May 24, 2004, and until his successor shall be elected and qualified, unless he shall resign or shall be removed or otherwise disqualified to serve.
Name, age and present
positions with Unocal
Recent business experience
CHARLES R. WILLIAMSON, 55
Chairman of the Board,
Chief Executive Officer and President
Chairman of Company Management Committee
Mr. Williamson has been Chairman of the Board since October 2001, Chief Executive Officer since January 2001 and President since February 2004. He has served as a Director since January 2000. He was Executive Vice President, International Energy Operations, during 1999 and 2000. He served as Group Vice President, Asia Operations, in 1998 and 1999.
TERRY G. DALLAS, 53
Executive Vice President
and Chief Financial Officer
Member of Company Management Committee
Mr. Dallas has been Executive Vice President since February 2001. He joined Unocal in 2000 as Chief Financial Officer. Previously, he was Senior Vice President and Treasurer of Atlantic Richfield Company (“Arco”), where he worked for 21 years.
SAMUEL H. GILLESPIE, III, 61
Senior Vice President, Chief Legal Officer, General Counsel and Corporate Secretary
Member of Company Management Committee
Mr. Gillespie joined Unocal on October 1, 2003. Mr. Gillespie joined Unocal from the Washington, D.C., office of the law firm of Skadden, Arps, Slate, Meagher and Flom, where he advised energy clients and worked on a variety of international projects. Previously, he was senior vice president and general counsel with Mobil Corporation, where he worked for 20 years.
THOMAS E. FISHER, 59
Senior Vice President,
Commercial Affairs.
Mr. Fisher has been Senior Vice President, Commercial affairs, since June 1998.
JOE D. CECIL, 55
Vice President and Comptroller
Mr. Cecil has been Vice President and Comptroller since December 1997.
DOUGLAS M. MILLER, 44
Vice President, Corporate Development
Mr. Miller has been Vice President, Corporate Development, since January 2000. From 1998 until 2000 he was General Manager, Planning and Development, International Energy Operations.
PART II
ITEM 5
ITEM 5 - MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
Prices in the foregoing table are from the New York Stock Exchange Composite Transactions listing. On February 27, 2004, the high price per share was $38.22 and the low price per share was $37.72.
Unocal common stock is listed for trading on the New York Stock Exchange.
As of February 27, 2004, the number of holders of record of Unocal common stock was 20,485 and the number of shares outstanding was 261,970,895.
Unocal’s quarterly dividend declared has been $0.20 per common share since the third quarter of 1993. The Company has paid a quarterly dividend for 88 consecutive years.
ITEM 6
ITEM 6 - SELECTED FINANCIAL DATA:
(a) Excludes earnings from equity investments.
(b) Includes liabilities associated with pre-paid commodity sales.
See Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7
ITEM 7 - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
Overview
The Company’s strategy is focused on creating value for its stockholders by continuing to advance oil and gas development projects and delivering successful exploration results through the drill bit. To this end, the Company achieved the following in 2003:
• Began production from West Seno field in Indonesia.
• Made significant deepwater discoveries: Saint Malo and Puma in the Gulf of Mexico and Gehem in Indonesia.
• Improved Finding and Development costs.
• Signed preliminary agreements in Thailand to extend gas sales contracts and increase contract volumes.
• Set plans to double oil production in Thailand by 2005.
• Restructured North American business to focus on core assets and increase profitability.
• Signed East China Sea exploration & production PSCs.
• Signed gas sales agreement for new field in Bangladesh.
• Made major progress on Phases I and II of the Azerbaijan International Operating Company (“AIOC”) development project and the Baku-Tbilisi-Ceyhan (“BTC”) pipeline from Baku, Azerbaijan to Ceyhan, Turkey.
Along with these accomplishments, the Company also had to work through a few setbacks:
• West Seno production experienced start-up delay and facility problems in Indonesia.
• Gulf of Mexico deep shelf exploration program results were disappointing.
The Company, along with the oil and gas industry, benefited from higher commodity prices, which continued an upward trend in 2003 and were near historical highs. Crude oil and natural gas prices are key variables that drive industry performance, and they can vary significantly. For example, the 2003 WTI average crude oil price was $31.06 per barrel and the average Henry Hub natural gas price was $5.49 per Mcf. This compared with $26.17 per barrel and $3.37 per Mcf in 2002. The Company’s worldwide production declined 5 percent in 2003 primarily due to asset sales in North America and the natural declines in existing fields in the Gulf of Mexico. During 2003, the Company generated $1.95 billion of net cash from operating activities, which it used in part to strengthen its balance sheet by paying down approximately $500 million of its debt and other financings.
The Company’s year-end 2003 proved oil and gas reserves were 1.759 billion BOE, compared with 1.774 billion BOE at the end of 2002. In 2003, the Company replaced production and nearly offset the sale of 98 million BOE. Including the net effect of sales, reserve replacement was 91 percent of 2003 production; reserve replacement was 149 percent excluding the net effect of sales. The Company’s finding, development and acquisition (“FD&A”) costs were approximately $7.05 per BOE, which was a major improvement from the $11.97 FD&A costs in 2002. Rising production costs remain a challenge and in 2004, the Company will be focused on improving its per unit production costs and finding and development costs, especially in its North American operations.
The Company’s pension related expenses were significantly higher in 2003 as compared to 2002. The low interest rate environment and lower market returns on plan assets during the 2000-2002 time period have negatively impacted the Company’s U.S. Qualified Retirement Plan. A detailed discussion regarding post-employment benefits may be found under the critical accounting policies section in this section and note 17 to the consolidated financial statements in Item 8 of this report.
The Company’s consolidated results are predominantly driven by the oil and gas exploration and production business; however, the Company does have other segments. The following discussion and analysis of the consolidated financial condition and results of operations of Unocal should be read in conjunction with the historical financial information provided in the consolidated financial statements and accompanying notes, as well as the business and properties descriptions in Items 1 and 2 of this report.
CONSOLIDATED RESULTS
Earnings From Continuing Operations
2003 vs. 2002 - Earnings from continuing operations were $710 million in 2003 compared to $330 million for 2002. Higher worldwide commodity prices increased net earnings by approximately $480 million. The Company’s worldwide average realized natural gas price, including a loss of 7 cents per Mcf from hedging activities, was $3.66 per Mcf in 2003. This was an increase of 85 cents per Mcf, or 30 percent, from the $2.81 per Mcf, including a benefit of 2 cents per Mcf from hedging activities, realized in 2002. In 2003, the Company’s worldwide average realized liquids price was $27.60 per Bbl, which was an increase of $4.46 per Bbl, or 19 percent, from a year ago. The Company’s hedging program lowered the average realized liquids price by 10 cents per Bbl in 2003 while 2002 included a gain of one cent per Bbl from hedging activities. International production increases also contributed approximately $35 million in higher earnings, primarily from higher Indonesia and Thailand liquids and natural gas production. In 2003, asset sales added after-tax gains of approximately $65 million, which included the sale of the Company’s equity interests in Matador Petroleum Corporation (“Matador”) and Tom Brown, Inc. (“Tom Brown”), and other asset divestitures in North America, compared to gains of approximately $26 million in 2002. The geothermal and power operations segment added $20 million in earnings improvement in 2003 as compared to 2002, primarily as a result of the amended Geothermal Salak energy sales agreements in Indonesia and improved results from the Company’s equity interests in gas-fired power plants in Thailand. The 2003 results included a $4 million after-tax gain on mark-to-market accruals and realized gains/losses for non-hedge commodity derivatives recorded by the Company’s Northrock subsidiary in Canada, compared with a $6 million after-tax loss in 2002. The 2003 results also benefited from the Canadian statutory tax rate changes, which added $29 million to net earnings. In addition, the Company recorded $17 million after-tax related to insurance settlements compared to $2 million after-tax for 2002. The 2002 results included $9 million after-tax for uninsured losses due to hurricane damage in the Gulf of Mexico and $8 million after-tax of costs related to the acquisition of the outstanding minority interest in Pure Resources, Inc. (“Pure”) common stock.
The positive variance factors discussed in the previous paragraph were partially offset by lower North America production, higher pension related expenses (see note 17 to the consolidated financial statements in Item 8 of this report), higher asset impairments primarily related to the Gulf region non-core property divestitures, the premiums paid for the early redemption of long-term debt and higher exploration expenses including dry hole costs, which reduced net earnings by approximately $80 million, $35 million, $30 million, $30 million and $15 million, respectively, in 2003 compared with 2002. North America liquids production averaged 81,000 Bbl/d in 2003, down from 94,000 Bbl/d a year ago, while natural gas production averaged 763 MMcf/d down from 886 MMcf/d for 2002. Most of the production decline was due to the divestiture of various properties in the Gulf of Mexico, onshore U.S. and Canada and the natural declines in existing fields in the Gulf of Mexico. In addition, the Company’s minerals operations recorded approximately $20 million after-tax in lower earnings for 2003 as compared to 2002 due primarily to lower mining margins and lower Brazil equity earnings.
After-tax environmental and litigation expenses were $110 million in 2003, compared with $91 million in 2002, reflecting higher litigation expenses including related outside support costs. The 2003 results included the company-wide $24 million after-tax restructuring charge (see note 7 to the consolidated financial statements in Item 8 of this report), while the same period a year ago included $14 million in after-tax restructuring charges for the Gulf Region and Alaska business units.
Income taxes on earnings from continuing operations in 2003 were $522 million compared with $280 million for 2002. The effective income tax rate was approximately 42 percent for 2003 as compared to approximately 45 percent in 2002. The lower effective tax rate for 2003 as compared with 2002 reflects the aforementioned benefit from the Canadian statutory tax rate changes and the mix of positive domestic and foreign earnings in 2003 compared to the mix of domestic losses and foreign earnings in 2002. Foreign earnings are generally taxed at higher rates than domestic earnings. Those factors were partially offset by currency-related adjustments in Thailand and tax adjustments related to the sale of affiliate investments in 2003.
2002 vs. 2001 - Earnings from continuing operations were $330 million in 2002, compared with $599 million in 2001. The decrease was primarily due to lower North America production and natural gas prices. Lower production in North America reduced net earnings by approximately $175 million from 2001. North America natural gas production averaged 886 MMcf/d in 2002, compared with 1,109 MMcf/d in 2001. The lower production was principally in the U.S. Lower 48 operations, which reflected lower Gulf of Mexico natural gas production stemming from the decline from Ship Shoal 295 field (“Muni”) production (10 MMcf/d, net of royalty, in 2002 versus 105 MMcf/d, net of royalty, in 2001), the natural declines in existing fields and hurricane-related production curtailments in the Gulf of Mexico. The lower production in North America was partially offset by higher production from International operations, which contributed approximately $25 million in higher 2002 after-tax earnings. Lower North America natural gas prices reduced net earnings by approximately $160 million in 2002. The Company’s North America average natural gas price, including a benefit of 5 cents per Mcf from hedging activities, was $2.88 per Mcf for 2002, which was a decrease of 97 cents per Mcf, or 25 percent, from the $3.85 per Mcf, including a loss of 4 cents per Mcf from hedging activities, in 2001.
The full-year results in 2002 included $25 million after-tax in higher pension related costs, a $15 million after-tax charge for impairments in Alaska, $14 million in after-tax restructuring charges for the Gulf Region and Alaska business units, $9 million after-tax for uninsured losses due to hurricane damage in the Gulf of Mexico and $8 million after-tax in costs related to the acquisition of the outstanding minority interest in Pure common stock. The full-year results in 2002 included an after-tax loss of $6 million in mark-to-market accruals and realized gains/losses for non-hedge commodity derivatives by the Company’s Northrock subsidiary, compared with an after-tax gain of $10 million in 2001. In 2002, net earnings benefited from $10 million after-tax related to participation agreements covering the Company’s former agricultural products business and former oil and gas operations in California, while the earnings impact in 2001 was $18 million.
The aforementioned negative earnings variances in 2002 were partially offset by lower dry hole costs compared with the previous year, which increased net earnings by approximately $40 million. The 2001 results also included an $86 million non-cash after-tax charge for impairments of certain Gulf of Mexico shelf and onshore properties, including those of an equity investee. In addition, after-tax environmental and litigation expenses were $92 million in 2002, compared with $108 million in 2001. The 2002 results 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. The 2002 results included $26 million in net after-tax gains from asset sales, while 2001 included $13 million in after-tax gains from asset sales.
Income taxes on earnings from continuing operations in 2002 were $280 million compared with $452 million for 2001. The effective income tax rate was approximately 45 percent for 2002 as compared to approximately 41 percent in 2001. The higher effective tax income tax rate in 2002, as compared to 2001, reflected the change in the mix of domestic losses and foreign earnings in 2002 compared to the mix of domestic and foreign earnings in 2001. Foreign earnings are generally taxed at higher rates.
Earnings From Discontinued Operations
Earnings from discontinued operations were $16 million in 2003, $1 million in 2002 and $17 million in 2001. The amounts in all three years primarily related to the Company’s 1997 sale of its former West Coast refining, marketing and transportation assets. The sales agreement contained a provision calling for payments to the Company for price differences between California Air Resources Board Phase 2 gasoline and conventional gasoline. This provision of the agreement terminated at the end of 2003. See note 9 to the consolidated financial statements in Item 8 of this report for details on discontinued operations.
Cumulative Effect of Accounting Change
In 2003, the Company recorded a non-cash $83 million after-tax charge for 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. In 2001, the Company recorded a one-time non-cash $1 million after-tax charge for the cumulative effect of a change in accounting principle related to the initial adoption of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.”
Operating Highlights
(b) Includes proportional shares of production of equity investees.
(c) Excludes Trade segment margins.
(d) Excludes gains/losses on derivative positions not accounted for as hedges and ineffective portion of hedges.
Operating Highlights (continued)
(b) Includes proportional shares of production of equity investees.
(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 operations did not have any hedging activities.
Sales and Operating Revenues
2003 vs. 2002 - Sales and operating revenues in 2003 were $6.40 billion, which was an increase of $1.17 billion from 2002. The increase was primarily due to higher average hydrocarbon commodity prices. Sales and operating revenues from the Trade business segment were $2.92 billion in 2003, which was an increase of $395 million from 2002. During 2003 and 2002, approximately 23 percent and 25 percent, respectively, of sales and operating revenues were attributable to the resale of crude oil, natural gas and natural gas liquids purchased from others in connection with the Trade segment’s marketing activities. These activities allow the Company to better manage its commodity-related risk and seek additional revenues beyond the market values available at producing locations by effectively transferring its production and commodity purchases to industry marketing centers with higher volumes of commercial activity and greater market liquidity.
2002 vs. 2001 - Sales and operating revenues in 2002 were $5.22 billion, which was a decrease of $1.48 billion from 2001. The decrease was primarily due to lower average hydrocarbon commodity prices, lower domestic natural gas production and reduced marketing activity related to the Company’s domestic equity crude production. Sales and operating revenues from the Trade business segment were $2.52 billion in 2002, which was a decrease of $1.33 billion from 2001. During 2002 and 2001, approximately 25 percent and 31 percent, respectively, of sales and operating revenues were attributable to the resale of crude oil, natural gas and natural gas liquids purchased from others in connection with the Trade segment’s marketing activities.
Sales of Assets
In 2003, the Company recorded pre-tax gains of $119 million from asset sales. The Company sold its equity interest shares held in Tom Brown and Matador, with a pre-tax gain of $100 million. The Company also completed the sale of various oil and gas properties in the Gulf of Mexico, onshore U.S. and Canada, which resulted in a net pre-tax gain of $8 million. The Company retained its deep mineral rights from a substantial portion of the properties sold in the Gulf of Mexico. The sale of various real estate and other miscellaneous properties resulted in pre-tax gains of $11 million. See note 4 in the consolidated financial statements in Item 8 of this report for a detailed discussion of the Company’s asset sales.
Selected Costs and Other Deductions
2003 vs. 2002 - Crude oil, natural gas and product purchases increased by $425 million in 2003. This increase was principally due to higher commodity prices. Administrative and general expense increased by $109 million in 2003. This increase primarily reflected $57 million of higher pension related expenses and the $38 million restructuring accrual in 2003 (see note 7 for details on restructuring). This higher level of pension related expenses is expected to continue for the next few years. The precise costs will depend primarily on future discount rates and the difference between the actual and expected return on plan assets. Depreciation, depletion and amortization expense was higher in 2003. This increase was primarily due to accretion on asset retirement obligations and increased DD&A rates per BOE from new higher cost fields. This increase in DD&A was partially offset by lower production from the Company’s North America operations. Impairments in 2003 were $93 million, which primarily reflected asset write-downs, to fair market value, of certain oil and gas fields in the Gulf of Mexico region that were sold in 2003. Interest expense was $11 million higher in 2003 primarily due to the premium paid on the early retirement of certain long-term debt, partially offset by higher capitalized interest.
While overall exploration expense remained relatively unchanged in 2003, the Company recorded higher amortization of exploratory leases. This increase was primarily due to a $26 million pre-tax provision that was a result of the Company’s relinquishment of 44 deepwater Gulf of Mexico blocks before their expiration dates. The Company intends to focus its deepwater Gulf of Mexico land position on those Outer Continental Shelf blocks that have more potential. This expense increase was partially offset by lower expenses of $18 million pre-tax, reflecting the relinquishment of certain exploration blocks in Gabon and Brazil in 2002.
2002 vs. 2001 - Crude oil, natural gas and product purchases decreased by $791 million in 2002. This decrease was principally due to lower purchases of domestic crude oil by the Trade segment in its marketing activities. In 2002, operating expense decreased by $82 million due to lower receivable provisions related to geothermal operations in Indonesia and lower environmental and litigation provisions. These two factors were partially offset by higher International operating expense primarily from added production operations in Thailand. Depreciation, depletion and amortization expense increased slightly in 2002, primarily due to higher production from expanded operations in Thailand, which was offset by lower production from the Company’s Gulf of Mexico operations. Impairments in 2002 were $47 million, which primarily reflected asset write-downs of certain oil and gas fields in Alaska and the Gulf of Mexico region, in addition to an impairment related to the Company’s investment in a U.S. pipeline company.
BUSINESS SEGMENT RESULTS
See note 31 to the consolidated financial statements in Item 8 of this report for a description of the Company’s reportable segments. The following business segment results should be read in conjunction with the business and properties descriptions in Items 1 and 2 of this report. The Company is organized in the following business segments:
Exploration and Production
The Company engages in oil and gas exploration, development and production worldwide. The results of this segment are discussed under two geographical breakdowns: North America and International.
North America
2003 vs. 2002 - After-tax earnings were $474 million in 2003 compared to $33 million in 2002. The increase was primarily due to higher natural gas and liquids prices, which increased net earnings by approximately $405 million. In addition, the Company recorded approximately $57 million after-tax in asset sale gains, primarily from the sale of Tom Brown and Matador common stock in 2003. In 2003, the Company recorded a $25 million deferred tax benefit adjustment related to statutory tax rate changes in Canada. In 2003, the results included after-tax gains of $4 million in mark-to-market accruals and realized gains/losses for non-hedge commodity derivatives recorded by Northrock, while the comparable period a year ago included an after-tax loss of $6 million. The 2002 results also included approximately $17 million in after-tax losses from asset sales, $14 million in after-tax restructuring charges in the Gulf Region and Alaska business units, $9 million after-tax for uninsured losses due to hurricane damage in the Gulf of Mexico, and $8 million in costs related to the acquisition of the outstanding minority interest in Pure common stock.
These positive factors were partially offset by lower natural gas and liquids production, higher impairments, higher DD&A rates and higher exploration expenses including dry hole costs, which reduced after-tax earnings by approximately $80 million, $40 million, $25 million and $10 million, respectively. In 2003, asset impairments in the Gulf Region business unit totaled $52 million after-tax and were primarily related to the sale of certain Gulf of Mexico assets that were held for sale, compared to 2002 impairments that totaled $12 million. In 2002, the Company’s Alaska business unit had an after-tax impairment of $15 million. Natural gas and liquids production was lower primarily due to a decrease in the Gulf of Mexico production from asset sales and natural field declines.
2002 vs. 2001 - After-tax earnings were $33 million in 2002 compared to $440 million in 2001. The decrease was primarily due to lower production and natural gas prices. Lower production in North America reduced net earnings by approximately $175 million from 2001. The lower production was principally in the U.S. Lower 48 operations, which reflected lower Gulf of Mexico natural gas production stemming from the decline in Muni production, the natural declines in existing fields and hurricane-related production curtailments in the Gulf of Mexico. Lower natural gas prices reduced after-tax earnings by approximately $160 million in 2002. The 2002 results also included a $17 million after-tax loss in asset sales, a $15 million after-tax charge for impairments in Alaska, $14 million in after-tax restructuring charges for the Gulf Region and Alaska business units, $9 million for uninsured losses due to hurricane damage in the Gulf of Mexico, $8 million in costs related to the acquisition of the outstanding minority interest in Pure common stock and an $10 million after-tax charge for impairments in the Gulf Region business unit. The 2002 results also included an after-tax loss of $6 million in mark-to-market accruals and realized gains/losses for non-hedge commodity derivatives by Northrock, compared with an after-tax gain of $10 million in 2001. These negative factors in 2002 were partially offset by lower dry hole costs compared with 2001 of approximately $20 million. Lower drilling activity in the Gulf of Mexico was partially offset by higher dry hole costs in Alaska. The 2001 results also included $86 million non-cash after-tax charge for impairments of certain Gulf of Mexico shelf and onshore properties, including those of an equity investee. After-tax earnings in 2001 also included $17 million in after-tax gains on the sale of certain Gulf of Mexico production properties.
International
2003 vs. 2002 - After-tax earnings totaled $561 million in 2003 compared to $503 million in 2002. The increase was primarily due to approximately $75 million in higher liquids and natural gas prices and $35 million in higher liquids and natural gas production. The higher natural gas production was primarily from increased demand tied to higher electric power needs in Thailand. Higher liquids production was due to the Yala-Plamuk and Pailin Phase 2 projects in Thailand and the start-up of the West Seno production in Indonesia. The 2003 exploration costs were $11 million after-tax lower than 2002 due to the relinquishment of exploration blocks in Gabon and Brazil that occurred in 2002. These positive factors were partially offset by approximately $25 million in higher DD&A expense (including asset retirement obligation accretion), $20 million in higher operating expenses primarily due to the new operations in Indonesia and $15 million in increased income taxes due to higher effective tax rates, primarily due to the weakening of the U.S. dollar against the Thai baht.
2002 vs. 2001 - After-tax earnings totaled $503 million in 2002 compared to $443 million in 2001. The increase was primarily due to $34 million in lower dry holes and exploratory costs, $30 million in higher natural gas and liquids prices, and $23 million in higher liquids and natural gas production. Dry hole costs for 2002 were lower, primarily due to exploratory dry holes in Brazil and Gabon in 2001 and lower Indonesia dry holes in the current year. Liquids production increased by approximately 4 percent, primarily from higher oil production in Thailand. Natural gas production increased 5 percent, primarily from Bangladesh, Myanmar and Brazil. The average natural gas price for International operations was $2.75 per Mcf in 2002 compared with $2.67 per Mcf in 2001. The average liquids price for International operations was $23.57 per Bbl in 2002, which was an increase of 60 cents per Bbl, or 3 percent, from 2001. These positive factors were partially offset by $15 million in higher operating expense.
Trade
2003 vs. 2002 - After-tax results were a $2 million loss in 2003 compared to after-tax earnings of $4 million in 2002. The decrease was primarily due to lower results related to domestic crude oil and natural gas marketing activities, which were negatively impacted by volatile commodity prices.
Sales and operating revenues were $2.92 billion in 2003 compared to $2.52 billion in the same period a year ago, which was an increase of $395 million. These revenues represented approximately 46 percent and 48 percent of the Company’s total sales and operating revenues for 2003 and 2002, respectively. In 2003, natural gas revenues increased by approximately $420 million and crude oil revenues decreased by approximately $20 million. Both natural gas and crude oil revenues benefited from higher commodity prices, as compared to a year ago. However, lower volumes for natural gas partially offset the positive impact of higher natural gas prices, while lower crude oil volumes more than offset the impact of higher crude oil prices. Lower crude oil revenues reflect management’s philosophy to decrease its outside crude oil purchases for resale due to continued volatility in the oil markets.
2002 vs. 2001 - After-tax earnings totaled $4 million in 2002 compared to $6 million in 2001. The lower results primarily reflected decreased domestic natural gas earnings from marketing activities due to lower production from the U.S. Lower 48 operations of the Exploration and Production segment and lower natural gas prices.
Sales and operating revenues were $2.52 billion in 2002 compared to $3.86 billion in 2001, which was a decrease of $1.34 billion. These revenues represented approximately 48 percent and 58 percent of the Company’s sales and operating revenues for 2002 and 2001, respectively. In 2002, crude oil revenues declined by approximately $650 million, primarily due to reduced activity in the purchase and resale of third-party barrels intended to take advantage of marketing opportunities, reflecting management’s continued efforts to decrease its outside crude oil purchases for resale due to increased volatility in the oil markets. Natural gas revenues declined by approximately $645 million, primarily due to lower U.S. domestic production volumes and commodity prices.
Midstream
2003 vs. 2002 - After-tax earnings totaled $73 million in 2003 compared to $104 million in 2002. The decrease was due primarily to $30 million in after-tax gains from the sales of certain investment interests in nonstrategic pipelines in the U.S. that occurred in 2002. The decrease was also due to $3 million in higher after-tax expenses related to the BTC pipeline project and a $7 million after-tax impairment related to the Trans-Andean oil pipeline in Argentina, which was held for sale at the end of 2003. These negative results were partially offset by $6 million after-tax in higher results in the natural gas storage and pipelines businesses and by a benefit of $4 million related to statutory tax rate changes in Canada.
2002 vs. 2001 - After-tax earnings totaled $104 million in 2002 compared to $54 million in 2001. The increase was due the aforementioned gains from asset sales. In addition, after-tax earnings in the gas storage business in 2002 improved by $14 million compared with 2001, and the pipeline business had an $8 million improvement in throughput volumes. The earnings from equity investees in 2002 also included $6 million in after-tax charges for a litigation provision and a project impairment related to the Colonial Pipeline Company and a $2 million after-tax asset impairment related to another U.S. pipeline company in which the Company owns an equity interest. The 2001 results included a $6 million after-tax asset write-down related to an investment by Colonial Pipeline Company.
Geothermal and Power Operations
2003 vs. 2002 - After-tax earnings totaled $50 million in 2003 compared to $30 million in 2002. The current year results reflect $8 million in higher earnings due to improvements from the amended Salak agreements in Indonesia. In addition, the results in 2003 reflect $9 million in higher earnings from the Company’s equity interests in gas-fired plants in Thailand due largely to favorable foreign exchange rates and $6 million in lower business development expenses as compared to 2002.
2002 vs. 2001 - After-tax earnings totaled $30 million in 2002 compared to $11 million in 2001. The improved results were due to approximately $33 million after-tax in lower receivable provisions related to geothermal operations in Indonesia as a consequence of the amended Salak agreements. This was partially offset by a decrease of $14 million from lower operational results in Indonesia and lower earnings results from the equity interests in the gas-fired power plants in Thailand.
Corporate and Other
2003 vs. 2002 - The after-tax earnings effect for 2003 was a loss of $446 million compared to a loss of $344 million in the same period a year ago. The 2003 results included $24 million after-tax in restructuring charges and higher pension related expenses of approximately $35 million. Net interest expense was $17 million higher in 2003, reflecting the $30 million after-tax in premiums paid for the early redemption of long-term debt, which was partially offset by higher capitalized interest on development projects. Environmental and litigation expenses were $107 million after-tax in 2003 compared to $93 million after-tax in 2002, primarily reflecting higher litigation support costs. In addition, the Company’s minerals operations recorded approximately $20 million after-tax in lower earnings for 2003 as compared to a year ago due primarily to lower mining margins and lower Brazil equity earnings.
2002 vs. 2001 - The after-tax earnings effect for 2002 was a loss of $344 million compared to a loss of $355 million in 2001. Environmental and litigation expenses were $93 million after-tax in 2002 compared to $108 million after-tax in 2001. In 2002, the results reflected approximately $15 million after-tax in higher minerals earnings compared to 2001. Net interest expense was $3 million lower in 2002, as higher interest expense from a premium on an early repayment of long-term debt was more than offset by higher capitalized interest on development projects. In 2002, earnings from real estate activities increased by $10 million after-tax and a $2 million after-tax gain from an insurance settlement was reached with insurers for the recovery of amounts previously paid out for environmental pollution claims and related costs. These positive factors in 2002 were partially offset by $25 million after-tax in higher pension related expenses.
LIQUIDITY and CAPITAL RESOURCES
(a) 2003 reflects an increase of $145 million due to changes in foreign currency translation adjustments. 2002 included $391 million reflecting the value of common stock issued to acquire Pure's outstanding common stock, which was offset by $334 million after-tax charge to other comprehensive income to recognize the minimum pension liability for the Company's U.S. Qualified Retirement Plan.
(b) Excludes interest rate swap derivatives. With the swaps included the ratios would be 8%, 5% and 7% for 2003, 2002 and 2001, respectively.
Liquidity is the Company’s ability to generate sufficient cash flows from operating activities to meet obligations and commitments. Cash generated from operations is the Company’s principal source of liquidity. The Company generally funds any additional liquidity requirements through debt issuance including commercial paper, the sale of a portion of its accounts receivable accounts through its receivable securitization program, and the use of revolving credit facilities to cover near-term borrowing requirements. Currently, the Company’s liquidity needs arise primarily from capital expenditures, cash dividends, working capital requirements and debt service. Based on current commodity prices and current development project expenditures, the Company expects cash generated from operating activities, asset sales and cash on hand in 2004 to be sufficient to cover these requirements. Further, the Company has substantial borrowing capacity to enable it to meet unanticipated cash requirements.
Cash Flows from Operating Activities
Net cash provided by operating activities was $1.95 billion in 2003, $1.57 billion in 2002 and $2.13 billion in 2001.
2003 vs. 2002 - Cash flows from operating activities increased by $378 million in 2003. The increase principally reflected the effects of higher worldwide commodity prices. In addition, the Company received $51 million in repayment of a loan made to PTT Exploration and Production Public Company Limited when the Company farmed into the Arthit field. The positive impact from higher prices was partially offset by higher income tax payments and higher interest paid compared to a year ago. In addition, cash flows from operating activities were reduced by the repayment of the outstanding balance under the Company’s accounts receivable securitization program.
2002 vs. 2001 - Cash flows from operating activities decreased by $554 million in 2002 versus 2001. This decrease principally reflected the effects of lower North America natural gas production volumes and lower worldwide commodity prices. The decrease was partially offset by $120 million in lower income tax payments, net of refunds, compared to 2001, an increase of $38 million from the sale of certain domestic trade receivables during 2002 (see note 12 to the consolidated financial statements in Item 8 of this report), and the receipt of $51 million from PT PLN (Persero) (“PLN”) in July 2002 for payment of past due receivables as a result of the agreement reached on the Indonesia geothermal contracts at Gunung Salak.
Capital Expenditures
The Company expects its overall capital expenditures in 2004 to increase by 17 percent from the 2003 level. The major component of this increase is due to capital spending for development projects in Indonesia and Thailand (International - Far East), which are expected to add approximately $170 million from the expenditure level in 2003. Another major factor contributing to the increase is the Xihu Trough project in China (International - Far East), which is expected to total $130 million in 2004, up from $10 million in 2003. The Caspian crude oil development project (International - Other) will remain a major portion of the capital expenditures in 2004 and is expected to total $295 million, up from $250 million in 2003. In addition, the Company expects its capital spending in Bangladesh (International - Other), to increase by $45 million in 2004, reflecting the development of natural gas from the Moulavi Bazar field. The increase from the aforementioned factors will be partially offset by $90 million in lower expenditures from the BTC pipeline project (Midstream).
2003 vs. 2002 - Capital expenditures for 2003 increased by 3 percent from 2002. Capital spending for large development projects, including the West Seno field in deepwater Indonesia (International - Far East ) and Mad Dog in the Gulf of Mexico (U.S. Lower 48), and the Caspian crude oil development (International - Other), and the associated BTC pipeline project (Midstream) totaled $655 million, up from $430 million in 2002. This increase from large development projects was mostly offset by $145 million in lower other development capital in North America and $15 million in lower worldwide exploration capital expenditures.
In 2003, the Company’s capital expenditures included approximately $770 million for the development of undeveloped proved oil and gas reserves, primarily in Indonesia, Azerbaijan, Thailand and the deepwater Gulf of Mexico.
2002 vs. 2001 - Capital expenditures for 2002 decreased slightly from 2001, but there was a significant shift in spending between exploration and development. Development capital increased 30 percent over 2001. Capital spending included approximately $500 million for the Mad Dog development project in the Gulf of Mexico (U.S. Lower 48), Phase I development in the Caspian (International - Other), the West Seno project in Indonesia and crude oil production development in Thailand (International - Far East), and the Caspian crude oil pipeline (Midstream). These expenditures were primarily offset by lower Gulf of Mexico exploration activity in 2002 and the 2001 exploration activity in Brazil (International - Other).
Major Acquisitions
The Company did not make any significant acquisitions in 2003. In 2002, the Company acquired the shares of Pure that it did not already own. This transaction, which was accomplished through an exchange of Unocal common stock, was valued at approximately $410 million and was accounted for as a purchase. In 2001, the Company formed a 50-50 joint venture with Forest Oil Corporation related to certain oil and gas properties located in the central Gulf of Mexico. The Company acquired a portion of proved reserves and production for approximately $113 million. Other significant acquisitions in 2001 included Pure’s acquisition of properties from International Paper Company for $267 million, Pure’s cash outlay of $173 million for the acquisition of all the shares of Hallwood Energy Corporation and Northrock’s cash outlay of $93 million for the acquisition of all the shares of Tethys Energy Inc.
Asset Sale Proceeds
In 2003, pre-tax proceeds from asset sales and discontinued operations were $653 million. The proceeds included approximately $361 million for the sale of various oil and gas properties in the Gulf of Mexico, onshore U.S. and Canada. The Company also received proceeds of $229 million from the sale of its equity interest shares held in Tom Brown and Matador. Cash proceeds also included approximately $52 million for the sale of various real estate and other miscellaneous properties. In addition, cash proceeds included $11 million 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.
In 2002, pre-tax cash proceeds received from asset sales and discontinued operations totaled $166 million. The proceeds included $65 million from the sale of certain investment interests in non-strategic pipelines in the U.S., $54 million from the sale of oil and gas assets primarily in the U.S. and approximately $44 million from the sale of real estate and other miscellaneous properties. The cash proceeds also included $3 million related to the aforementioned participation payment from the Company’s former West Coast refining, marketing and transportation assets.
In 2001, pre-tax proceeds from asset sales, including those classified as discontinued operations, were $106 million. The proceeds included a $25 million payment related to the aforementioned participation payment, $63 million from the sale of certain oil and gas properties, primarily in the U.S. Gulf of Mexico, and $18 million from the sale of real estate and other assets.
Long-term Debt
The Company’s long-term debt at year-end 2003, including the current portion, was $2.88 billion, approximately $125 million less than at the end of 2002. The Company retired $89 million in 9.25% debentures and paid down $10 million of medium-term notes that matured. The Company repurchased $194 million of debt principal through a tender offer, which included $115 million of the 7.20 percent notes due in 2005 and $79 million of the 6.50 percent notes due in 2008. The Company also repurchased $34 million of the 7.35% notes due in 2009, $34 million of the 9.125% debentures due in 2006, $27 million of the 6.375% notes due in 2004 and $26 million of medium-term notes in varying maturities. The Company also repaid $20 million of 6.20% Industrial Development Revenue Bonds due in 2008. In total, the Company paid approximately $35 million pre-tax ($30 million after-tax) in premiums for the early redemption of debt in 2003.
These decreases in debt were offset by $205 million drawn under the Overseas Private Investment Corporation (“OPIC”) Financing Agreement for the first phase of the West Seno development project in Indonesia. In addition, effective in the third quarter of 2003, the Financial Accounting Standards Board (“FASB”) issued Financial Interpretation No. 46 (“FIN 46”), “Consolidation of Variable Interest Entities,” which required the Company to consolidate its Dayabumi Salak Pratama, Ltd. (“DSPL”) subsidiary, resulting in the reporting of $74 million as long-term debt on the consolidated balance sheet. In 2003, the Company paid off the $252 million limited partner interest in Spirit Energy 76 Development, L.P. of which $242 million would have been reclassified as long-term debt in 2003 pursuant to FASB Interpretation No. 46 (see note 19 for further detail on the Company’s long-term debt).
The Company’s long-term debt at year-end 2002, including the current portion, increased by $90 million to $3.0 billion from $2.91 billion at year-end 2001. In 2002, the Company issued $400 million principal amount of 5.05 % notes with a maturity date of October 1, 2012. The net proceeds from the sale of the notes were primarily used to repay outstanding commercial paper that had been issued during the year. At December 31, 2002, the Company had no outstanding commercial paper. During 2002, the Company also retired $172 million of maturing medium-term notes. Northrock redeemed its $35 million “Series A” and $40 million “Series B” senior U.S. dollar-denominated notes. The Company also obtained a 3-year $295 million Canadian dollar-denominated non-revolving credit facility with a variable rate of interest. At December 31, 2002, the borrowings under the credit facility translated to $186 million using the applicable foreign exchange rate. At the end of 2002, Pure had no borrowings outstanding under its 3-year $275 million revolving credit facility or its $125 million (reduced from $235 million in December 2002) 5-year revolving credit facility. Outstanding borrowings under both facilities were repaid in the fourth quarter of 2002 subsequent to the Company’s acquisition of the outstanding Pure common shares. The Company cancelled both credit facilities in January 2003.
Contractual Obligations
The following table outlines various financial contractual obligations of the Company:
(a) See note 19 for details on long-term debt.
(b) See note 25 for detail on the trust convertible securities.
(c) See note 5 for detail on non-cancelable operating leases.
(d) Includes both accrued and future expenditures for significant purchase obligations and commitments.
(e) See note 2 for detail on SFAS No. 143 adoption for asset retirement obligations.
(f) See note 20 and 24 for detail on environmental liabilities.
(g) Payments reflect an estimate of the mandated annual contributions in 2004 and 2005 to the U.S. postretirement medical plan. Not included in the above table are expected future employer contributions to the U.S. postretirement plan of $30 million in 2006 and $61 million in 2007-2008 plus $96 million in the out years reflecting the remainder of the actuarially computed balance.
(h) Reflects projected mandated minimum funding contributions by the Company for U.S. Qualified Retirement Plan in 2006-2008 plus anticipated payments in support of the Company's Supplemental Executive Retirement Plan and unfunded foreign pension plans.
(i) See note 21 for further detail.
(j) Includes interest rate, foreign exchange rate and hydrocarbon derivatives and forward natural gas sale. See discussion in Item 7A
ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Market risk generally represents the risk that losses may occur in the values of financial instruments as a result of changes in interest rates, foreign currency exchange rates and commodity prices. As part of its overall risk management strategies, the Company uses derivative financial instruments to manage and reduce risks associated with these factors. The Company also trades hydrocarbon derivative instruments, such as futures contracts, swaps and options to exploit anticipated opportunities arising from commodity price fluctuations.
The Company determines the fair values of its derivative financial instruments primarily based upon market quotes of exchange traded instruments. Most futures and options contracts are valued based upon direct exchange quotes or industry published price indices. Some instruments with longer maturity periods require financial modeling to accommodate calculations beyond the horizons of available exchange quotes. These models calculate values for outer periods using current exchange quotes (i.e., forward curve) and assumptions regarding interest rates, commodity and interest rate volatility and, in some cases, foreign currency exchange rates. While the Company feels that current exchange quotes and assumptions regarding interest rates and volatilities are appropriate factors to measure the fair value of its longer termed derivative instruments, other pricing assumptions or methodologies may lead to materially different results in some instances.
Interest Rate Risk - From time to time the Company temporarily invests its excess cash in short-term interest-bearing securities issued by high-quality issuers. Company policies limit the amount of investment in securities of any one financial institution. Due to the short time the investments are outstanding and their general liquidity, these instruments are classified as cash equivalents in the consolidated balance sheet and do not represent a material interest rate risk to the Company. The Company’s primary market risk exposure to changes in interest rates relates to the Company’s long-term debt obligations. The Company manages its exposure to changing interest rates principally through the use of a combination of fixed and floating rate debt. Interest rate risk sensitive derivative financial instruments, such as swaps or options may also be used depending upon market conditions.
The Company evaluated the potential effect that near term changes in interest rates would have had on the fair value of its interest rate risk sensitive financial instruments at December 31, 2003. Assuming a ten percent decrease in the Company’s weighted average borrowing costs at December 31, 2003 and 2002, respectively, the potential increase in the fair value of the Company’s debt obligations and associated interest rate derivative instruments, including the debt obligations and associated interest rate derivative instruments of its subsidiaries, would have been approximately $93 million and $105 million at December 31, 2003 and 2002, respectively.
Foreign Exchange Rate Risk - The Company conducts business in various parts of the world and in various foreign currencies. To limit the Company’s foreign currency exchange rate risk related to operating income, foreign sales agreements generally contain price provisions designed to insulate the Company’s sales revenues against adverse foreign currency exchange rates. In most countries, energy products are valued and sold in U.S. dollars and foreign currency operating cost exposures have not been significant. In other countries, the Company is paid for product deliveries in local currencies but at prices indexed to the U.S. dollar. These funds, less amounts retained for operating costs, are converted to U.S. dollars as soon as practicable. The Company’s Canadian subsidiaries are paid in Canadian dollars for their crude oil and natural gas sales and have outstanding Canadian-dollar denominated debt.
From time to time the Company may purchase foreign currency options or enter into foreign currency swap or foreign currency forward contracts to limit the exposure related to its foreign currency debt or other obligations. At December 31, 2003, the Company had various foreign currency forward contracts outstanding related to operations in Thailand. The Company evaluated the effect that near term changes in foreign exchange rates would have had on the fair value of the Company’s combined foreign currency position related to its outstanding foreign currency swaps, forward contracts and foreign-currency denominated debt. Assuming an adverse change of ten percent in foreign exchange rates at December 31, 2003 and 2002, the potential decrease in fair value of the foreign currency swaps, foreign currency forward contracts and foreign-currency denominated debt of the Company and its subsidiaries would have been approximately $37 million and $35 million at December 31, 2003 and 2002, respectively.
Commodity Price Risk - The Company is a producer, purchaser, marketer and trader of certain hydrocarbon commodities such as crude oil and condensate, natural gas and refined products and is subject to the associated price risks. The Company uses hydrocarbon price-sensitive derivative instruments (“hydrocarbon derivatives”), such as futures contracts, swaps, collars and options to mitigate its overall exposure to fluctuations in hydrocarbon commodity prices. The Company may also enter into hydrocarbon derivatives to hedge contractual delivery commitments and future crude oil and natural gas production against price exposure. The Company also actively trades hydrocarbon derivatives, primarily exchange regulated futures and options contracts, subject to internal policy limitations.
The Company uses a variance-covariance value at risk model to assess the market risk of its hydrocarbon derivatives. Value at risk represents the potential loss in fair value the Company would experience on its hydrocarbon derivatives, using calculated volatilities and correlations over a specified time period with a given confidence level. The Company’s risk model is based upon current market data and uses a three-day time interval with a 97.5 percent confidence level. The model includes offsetting physical positions for any existing hydrocarbon derivatives related to the Company’s fixed price pre-paid crude oil and pre-paid natural gas sales. The model also includes the Company’s net interests in its subsidiaries’ crude oil and natural gas hydrocarbon derivatives and forward sales contracts. Based upon the Company’s risk model, the value at risk related to hydrocarbon derivatives held for hedging purposes was approximately $26 million and $20 million at December 31, 2003 and 2002, respectively. The value at risk related to hydrocarbon derivatives held for non-hedging purposes was immaterial at December 31, 2003, and approximately $4 million at December 31, 2002.
In order to provide a more comprehensive view of the Company’s commodity price risk, a tabular presentation of open hydrocarbon derivatives is also provided. The following table sets forth the future volumes and price ranges of hydrocarbon derivatives held by the Company at December 31, 2003, along with the fair values of those instruments.
Open Hydrocarbon Hedging Derivative Instruments (a)
(a) Positions reflect long (short) volumes.
(b) Net claims against counterparties with non-investment grade credit ratings are immaterial.
(c) Includes $3,541 thousand in assumed liabilities which were capitalized as acquisition costs.
Open Hydrocarbon Non-Hedging Derivative Instruments (a)
(a) Positions reflect long (short) volumes.
(b) Includes $5,034 thousand net claims against counterparties with non-investment grade credit ratings.
(c) Prices quoted from the New York Mercantile Exchange (NYMEX) and Inside FERC Gas Report (IFERC).
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ITEM 8
ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Index to the Consolidated Financial Statements and Financial Statement Schedule
All other financial statement schedules have been omitted as they are not applicable, not material or the required information is included in the financial statements or notes thereto.
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REPORT ON MANAGEMENT’S RESPONSIBILITIES
To the Stockholders of Unocal Corporation:
Unocal’s management is responsible for the integrity and objectivity of the financial information contained in this Annual Report. The financial statements included in this report have been prepared in accordance with generally accepted accounting principles and, where necessary, reflect the informed judgments and estimates of management.
The financial statements have been audited by the independent auditing firm of PricewaterhouseCoopers LLP. Management has made available to PricewaterhouseCoopers LLP all of the Company’s financial records and related data, minutes of the meetings of the Board of Directors and its executive committee and of the management committee and all internal audit reports. The independent auditors conduct a review of internal accounting controls to the extent required by generally accepted auditing standards and perform such tests and procedures, as they deem necessary to arrive at an opinion on the fairness of the financial statements presented herein.
Management maintains and is responsible for systems of internal accounting controls designed to provide reasonable assurance that the Company’s assets are properly safeguarded, transactions are executed in accordance with management’s authorization and the books and records of the Company accurately reflect all transactions. The systems of internal accounting controls are supported by written policies and procedures and by an appropriate segregation of responsibilities and duties. The Company maintains an extensive internal auditing program that independently assesses the effectiveness of these internal controls with written reports and recommendations issued to the appropriate levels of management. Management believes that the existing systems of internal controls are achieving the objectives discussed herein.
Unocal’s Audit Committee of the Board of Directors, consisting solely of independent directors, each of whom meets the independence standard of the New York Stock Exchange, is responsible for: assisting the Board in monitoring: 1) the integrity and reliability of the Company’s financial reporting; 2) the Company’s compliance with legal and regulatory requirements; 3) the adequacy of the Company’s internal operating policies and controls; and 4) the quality and performance of combined management, independent auditors, and the internal audit function. The Audit Committee is also responsible for the appointment of the independent auditors (which in turn is submitted to the stockholders for ratification) and reviewing their independence from the Company; and initiating special investigations as deemed necessary. The independent auditors and the internal auditors have full and free access to the Audit Committee and meet with it, with and without the presence of management, to discuss all appropriate matters.
/s/ CHARLES R. WILLIAMSON
/s/ TERRY G. DALLAS
/s/ SAMUEL H. GILLESPIE, III
/s/ JOE D. CECIL
Charles R. Williamson
Chairman of the Board,
Chief Executive Officer
and President
Terry G. Dallas
Executive Vice
President and Chief Financial Officer
Samuel H. Gillespie, III
Senior Vice President,
Chief Legal Officer,
General Counsel and Corporate Secretary
Joe D. Cecil
Vice President and Comptroller
March 11, 2004
REPORT OF INDEPENDENT AUDITORS
To the Board of Directors and Stockholders of Unocal Corporation:
We have audited the accompanying consolidated balance sheets of Unocal Corporation and its subsidiaries as of December 31, 2003 and 2002, and the related consolidated statements of earnings, cash flows and stockholders’ equity and comprehensive income for each of the three years in the period ended December 31, 2003 and the related financial statement schedule. These financial statements and financial statement schedule are the responsibility of Unocal Corporation’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above, which appear on pages 73 through 135 of this Annual Report on Form 10-K, present fairly, in all material respects, the consolidated financial position of Unocal Corporation and its subsidiaries as of December 31, 2003 and 2002 and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein, when read in conjunction with the related consolidated financial statements.
As discussed in Note 2 to the consolidated financial statements, Unocal Corporation changed its method of accounting for asset retirement costs as of January 1, 2003.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
February 17, 2004
cLos Angeles, California
CONSOLIDATED EARNINGS
UNOCAL CORPORATION
See Notes to the Consolidated Financial Statements.
CONSOLIDATED BALANCE SHEETS
UNOCAL CORPORATION
The Company follows the successful efforts method of accounting for its oil and gas activities.
See Notes to the Consolidated Financial Statements.
CONSOLIDATED CASH FLOWS
UNOCAL CORPORATION
See Notes to the Consolidated Financial Statements.
CONSOLIDATED STOCKHOLDERS’ EQUITY
UNOCAL CORPORATION
(a) At year-end 2003, other comprehensive income was comprised of unrealized currency translation gains of $45 million, deferred net losses on hedging instruments of $33 million and minimum pension liability adjustment of $310 million. Year-end 2002 other comprehensive income was comprised of unrealized currency translation losses of $100 million, deferred net losses on hedging instruments of $48 million and minimum pension liability adjustment of $338 million. Year-end 2001 other comprehensive income consisted of unrealized currency translation losses of $85 million, deferred net gains on hedging instruments of $60 million, minimum pension liability adjustment of $4 million and cumulative effect of accounting change of $59 million.
See Notes to the Consolidated Financial Statements.
COMPREHENSIVE INCOME
UNOCAL CORPORATION
See Notes to the Consolidated Financial Statements.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation - For the purpose of this report, Unocal Corporation (“Unocal”) and its consolidated subsidiaries, including Union Oil Company of California (“Union Oil”), will be referred to as the Company.
The consolidated financial statements of the Company include the accounts of subsidiaries in which a controlling interest is held and variable interest entities where the Company is the primary beneficiary. Investments in entities without a controlling interest are accounted for by the equity method. Under the equity method, the investments are stated at cost plus the Company’s equity in undistributed earnings and losses after acquisition. Income taxes estimated to be payable when earnings are distributed are included in deferred income taxes.
Use of Estimates - The consolidated financial statements are prepared in conformity with accounting principles generally accepted in the United States of America, which require management to make estimates and assumptions that affect the amounts of assets and liabilities and the disclosures of contingent liabilities as of the financial statement date and the amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Revenue Recognition - Revenues associated with sales of crude oil, condensate, natural gas, natural gas liquids and other products are recorded when title passes to the customer. Natural gas sales revenues from properties in which the Company has an interest with other producers are recognized on the basis of Unocal’s working interest (“entitlement” method of accounting). Natural gas imbalances occur when the Company sells more or less than its entitled ownership percentage of total natural gas production. Any amount received in excess of the Company’s share is treated as a liability. If the Company takes less than it is entitled, the under-delivery is recorded as a receivable. At December 31, 2003 and 2002, the Company had both receivables and payables related to under and over liftings of natural gas. The Company’s worldwide net gas imbalance was a receivable of $22 million and $29 million, for the two years respectively.
Inventories - Inventories are generally valued at the lower of cost or market. The costs of inventories are primarily determined using the last-in, first-out (“LIFO”) method or average costs method. Cost elements primarily consist of raw materials and production expenses.
Impairment of Assets - Oil and gas developed and undeveloped properties are regularly assessed for possible impairment, generally on a field-by-field basis where applicable, using the estimated undiscounted future cash flows of each field. Impairment losses are recognized when the estimated undiscounted future cash flows are less than the current net book values of the properties in a field. The measurement of the impairment amount to be recorded is based on expected discounted future cash flows or fair values. These expected future cash flows are estimated based on management’s plans to continue to produce and develop proved and associated risk-adjusted probable and possible reserves. Expected future cash flows from the sale or production of reserves are calculated based on management’s best estimate of future oil and gas prices using market-based information. The estimated future level of production is based on assumptions surrounding future commodity prices, lifting and development costs, field decline rates, market demand and supply, the economic regulatory climates and other factors.
Impairment charges are also made for other long-lived assets when it is determined that the carrying values of the assets may not be recoverable. A long-lived asset is reviewed for impairment whenever events or changes in circumstances indicate that the carrying value of the asset may not be recoverable.
Goodwill is not amortized but is reviewed for impairment on an annual basis and at other times when an event occurs or circumstances change that could negatively impact the fair value of a reporting unit. For purposes of goodwill, a reporting unit is the same as or one level below the Company’s operating segment. Fair value is determined by taking into consideration such factors as current commodity prices in cases where the present value of discounted cash flows are used in the valuation as well as externally available valuation data for similar operations in like geographic areas. If the carrying amount of a reporting unit exceeds its fair value, a purchase price type allocation is made to the identifiable assets and liabilities of the reporting unit as if acquired in a business combination and the remaining unallocated value is compared to recorded goodwill to determine if a write-down is required.
Asset Retirement Obligations (“AROs”) - Effective January 1, 2003, the Company adopted Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations,” (see note 2 for further details). This Statement requires that the Company recognize liabilities related to the legal obligations associated with the retirement of its tangible long-lived assets in the periods in which the obligations are incurred (typically when the assets are installed) if a reasonable estimate of fair value can be made. These obligations include the required decommissioning and removal of certain oil and gas platforms, plugging and abandonment of oil and gas wells and facilities, the closure of certain mining facilities, and the restoration of certain sites at the time of abandonment. The Company has interests in some long-lived assets, such as commercial natural gas storage facilities, commercial crude oil and products storage facilities and commercial pipelines where the operations are not tied to any particular operating field reserves. While these assets have retirement obligations under SFAS No. 143, certain of those obligations have not been recognized due to the uncertainties of the settlement dates of the obligations. The Company will continue to monitor these assets for any changes to this position.
Under SFAS No. 143, liabilities for asset retirement obligations are initially recorded at fair values and the carrying values of the related assets are increased by corresponding amounts. Over time, changes in the present value of the liabilities are accreted and expensed and the capitalized asset costs are depreciated over the useful lives of the corresponding assets. Recognized liability amounts are based upon future retirement cost estimates and incorporate many assumptions such as expected economic recoveries of crude oil and natural gas, time to abandonment, future inflation rates and the risk free rate of interest adjusted for the Company’s credit costs. Future revisions to ARO estimates will impact the present value of existing ARO liabilities and corresponding adjustments will be made to the capitalized asset retirement costs balance.
Oil and Gas Exploration and Development Costs - The Company follows the successful efforts method of accounting for its oil and gas activities. Acquisition costs of exploratory acreage are capitalized when incurred. Such costs related to the portion of properties expected to be non-commercial, based on exploratory experience and judgment, are amortized for impairment over the shorter of the exploratory period or the lease/concession holding period. This impairment amortization is reflected as a component of exploration expense on the consolidated earnings statement. Costs of successful leases are transferred to proved properties. Exploratory drilling costs are initially capitalized. If an exploratory well results in discovery of commercial reserves, the well investment is transferred to proved properties at the time reserves are booked. Costs of exploratory wells that have found commercially producible quantities of reserves that cannot be classified as proved remain capitalized while awaiting anticipated required major capital expenditures. Costs also remain capitalized for wells that have found sufficient quantities of reserves to justify their completion as long as the Company has firm plans to drill additional wells necessary to determine the existence of proved reserves. Exploratory wells that are non-commercial are expensed as dry holes. Geological and geophysical costs for exploration and leasehold rentals for unproved properties are expensed. Development costs of proved properties, including unsuccessful development wells, are capitalized.
Depreciation, Depletion and Amortization - Depreciation, depletion and amortization related to acquisition costs and development costs of proved properties, including capitalized abandonment and removal costs, are calculated at unit-of-production rates based upon total proved and proved developed reserves, respectively. Depreciation of other properties, including capitalized abandonment and removal costs, is generally on a straight-line method using various rates based on estimated useful lives.
Maintenance and Repairs - Expenditures for maintenance and repairs are expensed. In general, improvements are capitalized to the respective property accounts.
Retirement and Disposal of Properties - Upon retirement of facilities depreciated on an individual basis, remaining book values are charged to depreciation expense. For facilities depreciated on a group basis, remaining book values are charged to accumulated allowances. Gains or losses on sales of properties are included in current earnings.
Income Taxes - The Company uses the liability method for reporting income taxes, under which current and deferred tax liabilities and assets are recorded in accordance with enacted tax laws and rates. Under this method, the amounts of deferred tax liabilities and assets at the end of each period are determined using the tax rate expected to be in effect when taxes are actually paid or recovered. Future tax benefits are recognized to the extent that realization of such benefits is more likely than not.
Deferred income taxes are provided for the estimated income tax effect of temporary differences between financial and tax bases in assets and liabilities. Deferred tax assets are also provided for certain tax credit carryforwards. A valuation allowance to reduce deferred tax assets is established when deemed appropriate.
Foreign Currency Translation - Foreign exchange translation adjustments as a result of translating a foreign entity’s financial statements from its functional currency into U.S. dollars are included as a separate component of other comprehensive income in stockholders’ equity. The functional currency for all operations, except Canada and equity investments in Thailand and Brazil, is the U.S. dollar. Gains or losses incurred on currency transactions in other than a country’s functional currency are included in net earnings.
Environmental Expenditures - Expenditures that relate to existing conditions caused by past operations are expensed. Environmental expenditures that create future benefits or contribute to future revenue generation are capitalized.
Liabilities related to environmental assessments and future remediation costs are recorded when such liabilities are probable and the amounts can be reasonably estimated. The Company considers a site to present a probable liability when an investigation has identified environmental remediation requirements for which the Company is responsible. The timing of accruing for remediation costs generally coincides with the Company’s completion of investigation or feasibility work and its recommendation of a remedy or commitment to an appropriate plan of action. Environmental liabilities are not discounted or reduced by possible recoveries from third parties. However, accrued liabilities for Superfund and similar sites reflect anticipated allocations of liabilities among settling participants. Environmental remediation expenditures required for properties held for sale are capitalized up to the realizable market value.
Risk Management - The objectives of the Company’s risk management strategies include reducing the overall volatility of the Company’s cash flows, preserving revenues and pursuing outright pricing positions in hydrocarbon derivative financial instruments (hydrocarbon derivatives). As part of its overall risk management strategy, the Company enters into various derivative instrument contracts to offset portions of its exposures to changes in interest rates, changes in foreign currency exchange rates, and fluctuations in crude oil and natural gas prices. In general, the Company enters into derivative instruments to hedge two types of exposures: cash flow exposures and fair value exposures. Hedges of cash flow exposures are generally undertaken to reduce cash flow volatility associated with forecasted transactions. They may also be used to reduce volatility associated with cash flows to be paid related to recognized liabilities. Hedges of fair value exposures are undertaken to hedge recognized assets or liabilities or unrecognized firm commitments against changes in value.
Interest Rates - From time to time, the Company enters into interest rate swap contracts to manage the interest cost of its debt with the objective of minimizing the volatility and magnitude of the Company’s borrowing costs.
Foreign Currency - Various foreign currency forward, option and swap contracts are entered into by the Company to manage its exposures to adverse impacts of foreign currency fluctuations on recognized obligations and anticipated transactions.
Commodities - The Company uses hydrocarbon derivatives such as futures, swaps, collars and options to mitigate the Company’s overall exposure to fluctuations in hydrocarbon commodity prices. The Company also pursues outright pricing positions using derivatives.
In accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” all derivative instruments are recorded as assets or liabilities on the balance sheet at their fair values. The Company routinely enters into various purchase and sale contracts that will ultimately result in the physical delivery of hydrocarbon commodities. The Company has determined that the normal purchase and normal sale exception included in paragraph 10(b) of SFAS No. 133 applies to such contracts. Accordingly, such contracts are not accounted for as derivatives pursuant to SFAS No.133.
At the inception of a derivative contract, the Company may choose to designate and document a derivative as a cash flow hedge or a fair value hedge. Changes in the values of derivatives not designated and documented as hedges are recorded in current-period earnings.
Changes in the values of derivatives that qualify for, and are designated and effective as, cash flow hedges are deferred and recorded as components of accumulated other comprehensive income until the hedged transactions occur and are then recognized in earnings. Any ineffectiveness that is related to changes in the values of cash flow hedge derivatives is recognized immediately in earnings as a component of sales revenues. Changes in the values of derivatives that qualify for, and are designated and effective as, fair value hedges are recognized in current-period earnings as components of the line items reflecting the underlying hedged transactions. Changes in the fair values of the underlying hedged items (e.g., recognized assets, liabilities or unrecognized firm commitments) are also recognized in current-period earnings and offset the changes in the values of the corresponding hedging derivatives. Any resulting fair value hedge ineffectiveness is recognized in current-period earnings as the difference between the offsetting changes in values of the derivative and the underlying hedged items.
The Company documents its risk management objectives, its strategies for undertaking various hedge transactions and the relationships between hedging instruments and hedged items. Derivatives designated as cash flow hedges are linked to forecasted transactions. Derivatives identified as fair value hedges are linked to specific assets, liabilities or firm commitments. At hedge inceptions and on an on-going basis, the Company assesses whether changes in the values of derivatives used in hedging activities are highly effective in offsetting changes in the values of the hedged items. The Company discontinues hedge accounting prospectively when either (1) it determines that a derivative is not highly effective as a hedge, (2) the derivative is sold, exercised or otherwise terminated, (3) management elects to remove the derivative’s hedge designation, (4) the hedged transaction is no longer expected to occur, or (5) a hedged item no longer meets the definition of a firm commitment. When a hedged forecasted transaction is no longer expected to occur, the derivative continues to be carried on the balance sheet at its fair value and all unrealized gains and losses that were previously deferred in accumulated other comprehensive income are recognized immediately in earnings. When a hedged item no longer meets the definition of a firm commitment, the derivative continues to be carried on the balance sheet at its fair value and any asset or liability that was recorded on the balance sheet for the change in value of the hedged firm commitment is removed from the balance sheet and recognized immediately in current-period earnings. In all other situations where hedge accounting is discontinued, the derivatives continue to be carried on the balance sheet at their fair values and any prospective changes in their fair values are recognized in current-period earnings. Deferred gains and losses already recorded in accumulated other comprehensive income remain until the forecasted transactions occur, at which time those gains and losses are recognized in earnings.
Stock-Based Compensation - Prior to 2003, the Company applied Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations in accounting for stock-based compensation. Accordingly, stock-based compensation expense recognized in the Company’s consolidated earnings included expenses related to the Company’s various cash incentive plans that are paid to certain employees based upon defined measures of the Company’s common stock price performance and total shareholder return. In addition, the amounts also included expenses related to the Company’s Pure Resources, Inc. (“Pure”) subsidiary, which had its own stock-based compensation plans. Under APB Opinion No. 25, stock-based employee compensation cost was not recognized in earnings when stock options granted had an exercise price equal to the market value of the underlying common stock on the date of grant.
Effective January 1, 2003, the Company adopted the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” prospectively to all employee awards granted, modified, or settled after December 31, 2002. Therefore, the cost related to stock-based employee compensation included in the determination of net earnings for 2003 is less than that which would have been recognized if the fair value based method had been applied to all awards since the original effective date of SFAS No. 123. The following table illustrates the effect on net earnings and earnings per share if the fair value based method had been applied to all outstanding and unvested awards in each period:
Earnings Per Share - Basic earnings per share (“EPS”) is computed by dividing earnings available to common stockholders by the weighted-average number of common shares outstanding during the period. Diluted EPS is similar to basic EPS except that the denominator is increased to include the number of common shares that would have been outstanding if potential dilutive common shares had been issued. The numerator is also adjusted for convertible securities by adding back any convertible preferred distributions. Each group of potential dilutive common shares must be ranked and included in the diluted EPS calculation by first including the most dilutive, then the next dilutive, and so on, to the least dilutive shares. The process stops when the resulting diluted EPS is the lowest figure obtainable.
Capitalized Interest - Interest is capitalized on certain construction and development projects as part of the costs of the assets.
Other - The Company considers cash equivalents to be all highly liquid investments purchased with a maturity of three months or less.
Expenses incurred for transporting crude oil and natural gas are included as a component of operating expense.
Certain items in prior year financial statements have been reclassified to conform to the 2003 presentation.
NOTE 2 - ACCOUNTING CHANGES
SFAS No. 132 (revised 2003): In 2003, the Company adopted SFAS No. 132, “Employers” Disclosures about Pensions and Other Postretirement Benefits (revised 2003).” This Statement requires additional disclosures to those required in the original Statement relating to the assets, obligations, cash flows and net periodic benefit costs of defined benefit pension plans and other defined benefit postretirement plans. The adoption of the revised Statement did not have an effect on the Company’s financial position or results of operations. In accordance with this pronouncement, the benefit payment information will be included in the Company’s 2004 Form 10-K.
SFAS No. 143: Effective January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” If a reasonable estimate of fair value can be made, this Statement requires that the Company recognize liabilities related to the legal obligations associated with the retirement of its tangible long-lived assets in the periods in which the obligations are incurred (typically when the assets are installed). These obligations include the required decommissioning and removal of certain oil and gas platforms, plugging and abandonment of oil and gas wells and facilities and the closure and site restoration of certain mining facilities. The recognized liability amounts are based upon future retirement cost estimates and incorporate many assumptions such as expected economic recoveries of crude oil and natural gas, time to abandonment, future inflation rates and the risk free rate of interest adjusted for the Company’s credit costs.
The Company has interests in some long-lived assets, such as commercial natural gas storage facilities, commercial crude oil and products storage facilities, commercial pipelines, etc. where the operations are not tied to any particular operating field reserves. As the Company expects these assets to continue operations for the foreseeable future, it cannot reasonably estimate when, or if, these facilities will be abandoned. Accordingly, the Company has not accrued abandonment and restoration liabilities for these assets. The Company will continue to monitor these assets for any changes to this position.
Prior to January 1, 2003, the Company was required under SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” to accrue its abandonment and restoration costs ratably over the productive lives of its assets using the units-of-production method. SFAS No. 19 resulted in higher costs being accrued early in the fields’ lives when production was at its highest levels and abandonment and restoration costs accruals were matched with the revenues as oil and gas were produced.
Under SFAS No. 143, when the liabilities for asset retirement obligations are initially recorded at their fair value, capital costs of the related assets will be increased by equal corresponding amounts. Over time, changes in the present value of the liabilities will be accreted and expensed and the capitalized asset costs will be depreciated over the useful lives of the corresponding assets. Because SFAS No. 143 requires the use of interest accretion for revaluing asset retirement obligation liabilities as a result of the passage of time, associated accretion costs will be higher near the end of the fields’ lives when oil and gas production and related revenues are at their lowest levels.
APB Opinion No. 20, “Accounting Changes” requires that the Company calculate the retroactive impact of adopting SFAS No. 143 from the inception of its asset retirement obligations to its January 1, 2003 adoption date. APB Opinion No. 20 requires that this impact be quantified and reported as a cumulative effect of an accounting change on the earnings statement. This cumulative effect includes the catch up of SFAS No. 143 accretion expense related to the fair value of the liabilities as well as the catch up of associated depreciation expense related to the increased capital costs of the corresponding assets. The cumulative effect also includes the reversal of abandonment and restoration costs previously charged to earnings under SFAS No. 19. In addition to the impact on earnings due to the differences in applying SFAS No. 19 and SFAS No. 143 to the Company’s oil and gas operations, the cumulative effect also includes the impact related to the Company’s mining operations under SFAS No. 143.
In the first quarter of 2003, the Company recognized a one time after-tax charge of $83 million as the cumulative effect of an accounting change related to the adoption of SFAS No. 143. 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 as of January 1, 2003. The impact of adopting SFAS No. 143 on its 2003 operating earnings was an incremental charge of
approximately $18 million after tax. The change in the asset retirement obligation during 2003 is discussed in note 20. The following table presents the pro-forma effects of SFAS No. 143 on the liability balance for December 31, 2002 and 2001, and the pro-forma earnings information for the periods ended December 31, 2003, 2002 and 2001:
(a) Net earnings of $643 million for 2003 has been adjusted to remove the $83 million cumulative effect of accounting change attributable to SFAS No. 143.
SFAS No. 146: Effective January 1, 2003, the Company adopted SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” This Statement provides guidance on the recognition and measurement of liabilities associated with disposal activities. The adoption of the Statement did not have a material effect on the Company’s financial position or results of operations.
SFAS No. 148: Effective January 1, 2003, the Company adopted SFAS No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosure-an amendment of SFAS No. 123.” The Statement provides for three methods of transitioning from the intrinsic value to the fair value method of accounting for stock-based compensation. This Statement also amended the disclosure requirements of SFAS No. 123 and APB Opinion No. 28, “Interim Financial Reporting,” to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The disclosure requirements of the Statement were adopted in the Company’s 2002 Annual Report on Form 10-K. The Company adopted the fair value recognition provisions of SFAS No. 123, on a prospective basis, effective January 1, 2003 (see note 28 for further details). This change decreased 2003 after-tax income by $5 million. Adoption of the fair value recognition provisions did not have a material effect on the Company’s 2003 financial position.
SFAS No. 149: Effective July 1, 2003, the Company adopted SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” This Statement amends and clarifies accounting for derivative instruments including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133. The adoption of the Statement did not have a material effect on the Company’s financial position or results of operations.
SFAS No. 150: Effective April 1, 2003, the Company adopted SFAS No. 150, “Accounting for Certain Instruments with Characteristics of Both Liabilities and Equity,” which establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 requires that the Company classify a financial instrument that is within its scope, which may have previously been reported as equity, as a liability or an asset in some circumstances. The adoption of the Statement did not have an effect on the Company’s 2003 financial position.
FASB Interpretation No. 45: Effective January 1, 2003, the Company adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” This Interpretation requires the recognition of certain guarantees as liabilities at fair market value and is effective for guarantees issued or modified after December 31, 2002. The Company has included the disclosure requirements of the Interpretation in note 24. The adoption of this Interpretation did not have an effect on the Company’s financial position or results of operations.
FASB Interpretation No. 46: FASB Interpretation No. 46, “Consolidation of Variable Interest Entities (“VIE”)” requires the consolidation of certain entities that generally lack sufficient equity to finance their own activity without support from others or where there is an absence of control by equity investors. Although this Interpretation was effective for new variable interest entities as of February 1, 2003, the Company did not participate in any new VIEs in 2003. Pursuant to the recognition requirements of FASB Interpretation No. 46, the Company consolidated in the third quarter of 2003 the long-term debt of an affiliate that operates geothermal steam-fired power plants in Indonesia. At December 31, 2003, the balance sheet includes $74 million related to this debt (see note 19 for further details). An additional $242 million, classified as minority interests as of June 30, 2003, related to a partnership interest in Spirit Energy 76 Development, L.P. (“Spirit LP”), would have been required to be consolidated as long-term debt under this Interpretation had it not been paid in July 2003. FASB Staff Position No. FIN 46-6, delayed mandatory adoption of this rule until December 31, 2003, and permitted adoption on an entity-by-entity basis.
In December 2003, the FASB issued FASB Interpretation No. 46 (revised December 2003) which clarifies the definition of a VIE and provides a scope exception for certain entities that meet the Statement’s definition of a “business.” The Company will adopt this Standard in the first quarter of 2004, which will result in the deconsolidation of the Unocal Capital Trust (see note 25 for further details). As a result, the $522 million obligation for the convertible preferred securities will be removed from the consolidated balance sheet and replaced by a non-current liability for the $538 million in 6-1/4% convertible junior subordinated debentures of Unocal payable to the Trust. The Company will also record its $16 million investment in the Trust on the consolidated balance sheet. The deconsolidation will not effect consolidated net earnings. Because of its complexities, the Company continues to review the revised Statement and may find additional material interests in entities which could require recognition or disclosure in the first quarter 2004 financial statements.
Other Matters: The Company has classified the cost of acquiring oil and gas drilling rights in property, plant and equipment. The FASB’s Emerging Issues Task Force (“EITF”) has on their agenda Issue No. 03-S, “Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to Oil and Gas Companies.” This issue addresses whether oil and gas drilling rights are intangible assets, and whether those assets are subject to classification and disclosure provisions of SFAS No. 142. The resolution of this issue will have no impact on the Company’s results of operations and statement of cash flows. If the EITF determines that the cost of oil and gas drilling rights should be classified as intangible assets, it would result in additional disclosures and a balance sheet reclassification of these assets from “Properties-net” to “Intangible Assets” amounting to approximately $1,527 million and $1,746 million at December 31, 2003 and 2002, respectively.
In December 2003, “The Medicare Prescription Drug, Improvement and Modernization Act of 2003” (the “Act”) was enacted, which introduces a prescription drug benefit under Medicare Part D. The availability of the new drug benefit could cause medicare eligible plan participants to leave their current employer-sponsored plans (or cause employees to join such plans), depending on the drug benefits provided under those plans relative to the benefits provided by Medicare. The Act also provides that a non-taxable federal subsidy will be paid to sponsors of postretirement benefit plans that provide retirees with a drug benefit that is at least “actuarially equivalent” to the Medicare Part D benefit. In accordance with FASB Staff Position 106-1, the Company has deferred the accounting for this Act and thus any measures of the accumulated postretirement benefit obligation or net periodic postretirement benefit cost in the consolidated financial statements or accompanying notes do not reflect the effects of the Act on the plan. Specific authoritative guidance on the accounting for the federal subsidy is pending and that guidance, when issued, could require the sponsor to change previously reported information. The Company is studying the Act to determine its economic impact. The federal subsidy is not payable to a plan sponsor for retirees who leave their current employer-sponsored plan to participate in the Medicare drug program. Detailed regulations specifying the manner in which actuarial equivalency must be determined and the evidence required to demonstrate it are not yet available. It is not known whether the Company will amend the plan in response to the new legislation.
NOTE 3 - ACQUISITIONS
The Company did not make any significant acquisitions in 2003. In 2002, the Company exchanged shares of its common stock for the remaining shares of Pure that it did not already own. Consequently, Pure became a wholly owned subsidiary of the Company. This transaction was valued at approximately $410 million and was accounted for as a purchase. At December 31, 2002, as a result of the transaction, properties increased by $121 million, goodwill increased by $80 million representing the excess of cost over fair values of the asset and liabilities acquired, deferred tax liabilities increased by $53 million, long-term debt increased by $10 million, reflecting the fair value of Pure’s debt, and stockholders’ equity increased by $391 million for the value of the common stock. As a result of the transaction, a minority interest liability of $151 million and a $112 million obligation for “Subsidiary stock subject to repurchase” were eliminated from the Company’s consolidated balance sheet.
NOTE 4 - DISPOSITIONS OF ASSETS
In 2003, pre-tax proceeds from sales of assets totaled $642 million, with pre-tax gains of $119 million. The proceeds included approximately $361 million for the sale of various oil and gas properties in the Gulf of Mexico, onshore U.S. and Canada with a pre-tax gain of $8 million. In the Gulf of Mexico, the Company retained its deep mineral rights from a substantial number of the properties sold. The Company also received proceeds of $229 million from the sale of its equity interest shares held in Tom Brown Inc. and Matador Petroleum Corporation, with a pre-tax gain of $100 million. Cash proceeds also included approximately $52 million with a pre-tax gain of $11 million for the sale of various real estate and other miscellaneous properties.
In 2002, cash proceeds received from sales of assets totaled $163 million, with pre-tax gains of $42 million. The proceeds included $65 million from the sale of certain investment interests in nonstrategic pipelines in the U.S, with a pre-tax gain of $49 million. Cash proceeds of approximately $44 million were from the sale of real estate and other miscellaneous properties, with a pre-tax gain of $20 million, and $32 million were from the sale, by the Company’s Pure subsidiary, of oil and gas producing properties in the U.S, with a pre-tax gain of $4 million. Sale proceeds also included $22 million from various other oil and gas asset sales, with a pre-tax loss of $31 million.
In 2001, cash proceeds received from sales of assets totaled $81 million, with pre-tax gains of $24 million. The Company received $63 million from the sale of certain oil and gas properties, primarily located in the U.S. Gulf of Mexico, with a pre-tax gain of $21 million. In addition, the Company received $18 million from the sale of real estate and other assets, with a pre-tax gain of $3 million.
NOTE 5 - LEASE RENTAL OBLIGATIONS
The Company has operating leases for drilling rigs, office space and other property and equipment having initial or remaining noncancelable lease terms in excess of one year.
Future minimum rental payments for operating leases at December 31, 2003 were as follows:
The Company has a lease agreement relating to the Discoverer Spirit deepwater drillship, with a remaining term of approximately 21 months at December 31, 2003. The drillship has a current minimum daily rate of approximately $226,000. The future remaining minimum lease payment obligation was approximately $140 million at December 31, 2003.
The future minimum lease rental payments have not been reduced, in total, by minimum sublease rentals due in the future under non-cancelable subleases.
Net operating lease rental expense for continuing operations was as follows:
NOTE 6 - IMPAIRMENT OF ASSETS
The Company, as part of its regular assessment, reviewed its developed and undeveloped oil and gas properties and other long-lived assets for possible impairment. It also reviewed its properties as they were identified for sale.
In 2003, the Company recorded pre-tax impairment charges of $85 million ($53 million after-tax) for oil and gas fields (E&P - North America-U.S. Lower 48) and associated pipelines (Midstream) in the Gulf of Mexico region that were targeted and sold in a divestment of non-core assets. The properties targeted were low margin properties in the Gulf of Mexico region (see note 4). In addition, the Company recorded an after-tax charge of $6 million in its Midstream segment due to the impairment of the Trans-Andean oil pipeline in Argentina, which was held for sale at the end of 2003.
In 2002, the Company recorded pre-tax charges of $41 million (26 million after-tax) for the impairment of oil and gas fields in Alaska and the Gulf of Mexico region primarily due to lower reserve estimates, production forecasts and future expenses. The impairment in Alaska was $24 million pre-tax while the impairment for the Gulf of Mexico region was $17 million pre-tax. The Company also recorded a pre-tax charge of $4 million, for the impairment of its investment in a U.S. pipeline company that was being held for sale, carried in its Midstream segment as an equity affiliate. Lastly, the Company recorded a pre-tax charge of $2 million to impair its investment in an electronic commerce provider.
In 2001, the Company recorded pre-tax charges of $118 million ($74 million after-tax) for the impairment of certain oil and gas properties, primarily located in the Gulf of Mexico shelf, due principally to lower commodity prices. Earnings from equity investments included pre-tax charges of $19 million ($12 million after-tax), reflecting the Company’s portion of the impairment of certain oil and gas Gulf of Mexico shelf properties held by one of its equity investees.
NOTE 7 - RESTRUCTURING COSTS
In June 2003, the Company accrued a $27 million pre-tax restructuring charge and adopted a plan for streamlining the organizational structures in order to align them with the Company’s portfolio requirements and business needs. In the third quarter of 2003, the Company accrued an additional $10 million pre-tax restructuring charge to reflect continued streamlining of the organizational structures. An additional $1 million pre-tax charge was accrued in the fourth quarter when benefits for the additional participants became probable. These charges are included in administrative and general expense on the consolidated earnings statement. The following table reflects the 2003 restructuring activity by quarter. The majority of the remaining liability is expected to be paid in 2004. At December 31, 2003, 335 of 360 employees had been terminated or had been advised of planned termination dates as a result of the plan.
In June 2002, the Company’s Gulf Region business unit, which is part of the U.S. Lower 48 operations in the Exploration and Production segment, adopted a restructuring plan that resulted in the accrual of a $19 million pre-tax restructuring charge. The charge reflected the costs of terminating 202 employees. At year-end 2003, the restructuring costs had been paid and charged against the liability.
In November 2002, the Company adopted a restructuring plan that resulted in the accrual of a $4 million pre-tax restructuring charge related to Exploration and Production operations in Alaska. The restructuring charge reflected the costs of terminating 46 employees. The plan was completed in 2003.
NOTE 8 - INCOME TAXES
The components of the income tax provision for continuing operations were as follows:
(a) Amounts attributable to the Corporate and Other segment are allocated.
In 2003, the Company elected to carry the U.S. federal net operating loss incurred in 2002 forward into 2003 to reduce federal taxable income. In addition, in 2003 the Company expects to utilize a portion of the past net operating loss carryforwards generated by its Pure subsidiary. The 2002 provision reflects a decrease in current foreign tax provision of $78 million and an increase in deferred foreign tax provision of $89 million due to the settlement of past issues as a result of renegotiating the geothermal sales contract in Indonesia. The Indonesia geothermal adjustments relate to prior year tax provisions and have no cash flow impact.
The following table is a reconciliation of income taxes at the federal statutory income tax rates to income taxes as reported in the consolidated earnings statement.
The significant components of deferred income tax assets and liabilities included in the consolidated balance sheet at December 31, 2003 and 2002 were as follows:
No deferred U.S. income tax liability has been recognized on the undistributed earnings of foreign subsidiaries that have been retained for reinvestment. If distributed, no additional U.S. tax is expected due to the availability of foreign tax credits. The undistributed earnings for tax purposes, excluding previously taxed earnings, were estimated at $2.4 billion as of December 31, 2003. The Company estimates that approximately $215 million of unused foreign tax credits will be available after the filing of the 2003 consolidated tax return, with various expiration dates through the year 2008. No deferred tax asset for these foreign tax credits has been recognized for financial statement purposes.
At December 31, 2003, the Company had $106 million of federal alternative minimum tax credits which are available to reduce future U.S. federal income taxes on an indefinite basis. At December 31, 2003, the Company had net operating loss carryforwards of approximately $9 million, which are available to offset future taxable income subject to annual limitations. The loss carryforwards begin to expire in 2019, and the tax effect of those carryforwards are included in other deferred tax assets.
NOTE 9 - DISCONTINUED OPERATIONS
(a) Gain on disposal in 2003, 2002 and 2001 is related to the former refining, marketing and transportation business.
In 2003, discontinued operations included a $25 million pre-tax gain relating to the Company’s 1997 sale of its former West Coast refining, marketing and transportation assets. The sales agreement contained a provision calling for payments to the Company for price differences between California Air Resources Board Phase 2 gasoline and conventional gasoline. In 2003, the Company recorded $14 million pre-tax for this provision. The gains in 2002 and 2001 were also related to this agreement. The Company’s cash proceeds related to the agreement were $11 million, $3 million and $25 million for 2003, 2002 and 2001, respectively. This provision in the agreement terminated at the end of 2003. In addition, the Company also reduced its loss provisions for the disposal of the business by $11 million pre-tax, reflecting lower than anticipated charges relating to the sold properties.
NOTE 10 - EARNINGS PER SHARE
The following table includes a reconciliation of the numerators and denominators of the basic and diluted EPS computations for earnings from continuing operations for the years 2003, 2002 and 2001.
(a) The effect of assumed conversion of preferred securities on earnings per share is antidilutive.
Not included in the computation of diluted EPS at December 31, 2003, 2002 and 2001, were options outstanding to purchase approximately 8.2 million, 7.2 million and 6.2 million shares of common stock, respectively. These options were not included in the computation as the exercise prices were greater than the average market price of the common shares during the respective years.
NOTE 11 - CASH AND CASH EQUIVALENTS
At December 31, 2003, the Company’s cash and time deposits had increased by $183 million from year-end 2002, reflecting the effect of stronger commodity prices during the year. At year-end 2003, marketable securities totaled $53 million reflecting the Company’s short-term investment in two money market funds that invest in U.S. Treasury and other U.S. government agency obligations, floating rate and variable rate demand notes of U.S. and foreign corporations, commercial paper rated in the highest category by Moody’s Investor Services, Inc. (P1) and Standard & Poor’s Ratings Services (A1), certificates of deposit and time deposits, asset backed securities and repurchase agreements. The funds are rated “Aaa” by Moody’s Investors Service, Inc. and “AAAm” by Standard & Poor’s Ratings Services.
NOTE 12 - SALES OF ACCOUNTS RECEIVABLE
The Company, through a bankruptcy remote wholly-owned subsidiary, Unocal Receivables Corporation (“URC”), has a sales agreement with an outside unrelated party that provides for the sale of up to $125 million of an undivided interest in domestic crude oil and natural gas trade receivables. Under the terms of the agreement, the receivables are sold at a discount on a revolving basis and without recourse. The costs incurred under the agreement for the years ended December 31, 2003 and 2002, were $1 million and $2 million, respectively, and were charged to operating expense in the consolidated earnings statement. Amounts sold were reflected as a reduction of accounts and notes receivable in the consolidated balance sheet and in net cash provided by operating activities in the consolidated cash flows statement. The Company used this arrangement throughout 2003 but had no outstanding balance at December 31, 2003. At year-end 2002, the Company had sold $108 million of its domestic trade receivables under this agreement.
The Company’s consolidated balance sheet included a note receivable from URC of approximately $182 million and $66 million at December 31, 2003 and 2002, respectively, representing the unsold balance of trade receivables transferred to URC.
NOTE 13 - INVENTORIES
Inventories are generally valued at the lower of cost or market. Inventories using the LIFO cost method amounted to $17 million and $12 million as of December 31, 2003 and 2002, respectively. The remaining inventory balances were primarily valued using average cost. The current replacement cost of inventories exceeding the LIFO inventory values was $3 million and $4 million at December 31, 2003 and 2002, respectively.
NOTE 14 - ASSETS HELD FOR SALE
At December 31, 2003, the Company was in the process of selling certain of its prospective mineral fee lands in North America. The assets involved in the proposed sale included approximately 3.2 million net acres, primarily in Texas, Louisiana, Mississippi and Alabama.
At December 31, 2003, the Company’s Unocal North Sumatra Geothermal, Ltd. subsidiary had agreed to sell its rights and interest in the Sarulla geothermal project on the island of Sumatra, Indonesia to the state electricity company of Indonesia. The sales price was $60 million and the transaction closed in February 2004 (see note 32 - Subsequent Event).
The Company is in the process of selling its interests in the Trans-Andean oil pipeline, which transports crude oil from Argentina to Chile. The Company recorded an after-tax impairment on the transaction of approximately $6 million in 2003.
Details of the assets classified as held for sale, as of December 31, 2003, are presented below:
NOTE 15 - EQUITY INVESTMENTS
Investments in companies accounted for by the equity method were $651 million, $686 million and $625 million at December 31, 2003, 2002 and 2001, respectively. These investments are reported in investments and long-term receivables on the consolidated balance sheet.
Dividends or cash distributions received from the Company’s equity investees were $180 million, $132 million and $211 million for the years 2003, 2002 and 2001, respectively. At December 31, 2003, 2002 and 2001, the excess of the Company’s investments in Colonial Pipeline Company and various other pipeline companies was $139 million, $143 million and $153 million, respectively. These equity investees have approximately $1.5 billion of their own debt obligations that are either fully non-recourse or of limited recourse to the Company. Of the total $1.5 billion in equity investee debt, $1.2 billion is that of Colonial Pipeline Company, in which the Company holds a 23.44 percent equity interest. The Company guarantees $19 million of the $1.5 billion total. At December 31, 2003, 2002 and 2001, the Company’s shares of the net capitalized costs of other companies engaged in oil and gas exploration and production activities were $178 million, $347 million and $309 million, respectively.
Summarized financial information for these investments and the Company’s equity shares are presented in the table below.
NOTE 16 - PROPERTIES AND CAPITAL LEASES
Investments in owned and capitalized-leased properties are shown below. Accumulated depreciation, depletion, and amortization for continuing operations were $11,711 million and $12,277 million at December 31, 2003 and 2002, respectively.
NOTE 17 - POSTEMPLOYMENT BENEFIT PLANS
The Company has numerous plans worldwide that provide eligible employees with retirement benefits. The Company also has medical plans that provide health care benefits for eligible employees and many of its retired employees. Most of the Company’s plans covering employees outside of North America are unfunded and resulting liabilities are extinguished on a “pay as you go” basis. The functional currency for all of the Company’s international plans, with the exception of Canada, is the U.S. dollar.
Prepaid pension costs are reported as a component of investments and long-term receivables on the consolidated balance sheet. Postemployment benefit liabilities, including pensions, postretirement medical benefits and other postemployment benefits, are reported as a component of other deferred credits and liabilities on the consolidated balance sheet. The Company uses a December 31 measurement date for all of its postemployment benefit plans. The following table sets forth the postretirement benefit obligations recognized in the consolidated balance sheet at December 31, 2003 and 2002.
The accumulated benefit obligation for the Company’s defined benefit pension plans was $1,203 million and $1,055 million at December 31, 2003, and 2002, respectively. The projected benefit obligations, accumulated benefit obligations and fair values of plan assets for pension plans with accumulated benefit obligations in excess of plan assets were approximately $1,323 million, $1,155 million and $937 million, respectively as of December 31, 2003 and approximately $1,152 million, $1,019 million and $833 million, respectively as of December 31, 2002.
Net periodic pension and postretirement benefit cost are comprised of the following components:
The Company recognized $5 million in curtailment costs related to its U.S. Qualified Retirement Plan and Postretirement Welfare plans covering current and former U.S. payroll employees as a result of asset sales and the Company’s 2003 restructuring plan. The Company amortizes the cost of plan amendments and unrecognized actuarial gains and losses on a straight-line basis over the average remaining service period of active plan participants expected to receive benefits.
The assumed weighted-average rates used to determine benefit obligations at December 31 were:
For the years ended December 31, the assumed weighted average rates used to determine net periodic benefit cost were:
The Company employs a building block approach in determining the expected long-term rate of return for pension plan assets. Current market factors such as inflation and interest rates are evaluated before long-term capital market assumptions are determined. The overall expected long-term rate of return on assets assumption is calculated using pension plan target asset allocations, outside consultants’ capital markets return forecasts for the asset classes employed, expected premium returns for active management and estimated pension plan fees and expenses. Peer data and historical returns are utilized to validate projected long-term returns for reasonableness. The resulting weighted average expected long-term rate of return for the Company’s domestic and international pension plans were 8.0 percent and 8.4 percent at January 1, 2004 and 2003, respectively.
The following is a breakdown of the fair value of the Company’s pension plan assets by investment type at December 31, 2003 and 2002, respectively:
The investment objective is to maximize investment earnings and capital appreciation on plan assets and to preserve capital over a long-term horizon. This objective is achieved by investing in equities and other asset classes with differing rates of return, return variances and correlation so as to provide diversification and to mitigate risks. The Company’s current asset allocation policy for its U.S. Qualified Retirement Plan is set forth below:
Asset allocations are reviewed periodically to ascertain that the desired asset mix is being maintained based on the return potential and risk factors associated with each asset class. Outside investment advisors are hired to manage plan assets and are selected based on their particular investment style, philosophy and past performance. Specific guidelines are in place for each investment advisor and are strictly enforced. Other than through index funds none of the plans hold shares of the Company’s common stock.
In 2002, the Company recognized a minimum pension liability of $103 million reflecting the excess of the accumulated benefit obligation over the fair value of plan assets at December 31, 2002 for its U.S. Qualified Retirement Plan covering current and former U.S. payroll employees. The recognition of this liability resulted in an after-tax charge of $334 million to the other comprehensive income component of stockholders’ equity. At December 31, 2003 the minimum pension liability reflecting the excess of the accumulated benefit obligation over the fair value of plan assets for the Company’s U.S. Qualified Retirement Plan had been reduced to $91 million. This net reduction was achieved in spite of using a lower discount rate to measure the liability at year-end 2003 and reflects the improved market returns on plan assets during 2003. As a result, an after-tax credit of $34 million was recorded to the other comprehensive income component of stockholders’ equity in 2003.
The Company made a voluntary $30 million cash contribution to its U.S. Qualified Retirement Plan in the fourth quarter of 2003. The Company will not be required under existing funding or tax regulations to make any cash contributions to its U.S. Qualified Retirement Plan during 2004. The Company anticipates that it will contribute approximately $4 million to its Supplemental Executive Retirement plans, approximately $17 million to its foreign pension plans and approximately $27 million to its worldwide postretirement medical plans in 2004.
Health care cost trend rates used in measuring the benefit obligation for the U.S. medical plans at December 31 are set forth as follows:
A one percentage-point change in the assumed health care cost trend rate would have had the following effects on 2003 service and interest cost and the accumulated postretirement benefit obligation at December 31, 2003:
In December 2003, the U.S. Congress passed the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“the Act”). The Company is still in the process of evaluating the impact of the Act on its U.S. Postretirement Welfare plan. In keeping with the guidance provided by the Financial Accounting Standards Board in its FASB Staff Position No. FAS 106-1, the Company has elected to defer accounting for the effects of the Act (see note 2 for further details). Accordingly, the accumulated postretirement benefit obligation and net periodic benefit cost reported in the Company’s financial statements for the period ended December 31, 2003 do not reflect the effects of the Act. In addition, specific authoritative guidance on the accounting for the federal subsidy to qualifying plans is still pending and that guidance, when issued, could require the Company to change previously reported information.
The Company has a 401(k) defined contribution savings plan designed to supplement retirement income for its U.S. employees. The Company’s contributions to the plan were $13 million, $12 million and $11 million in 2003, 2002 and 2001 respectively, which were used by the plan trustee to purchase shares of Unocal common stock in the open market. While historically trustee purchases of Unocal common stock have been made in the open market the Company has the option to direct the trustee to purchase common stock directly from Unocal. Once the Company’s contributions have been used to purchase Unocal common stock, employees have the ability to convert the shares to other investment options, including a variety of mutual funds and a money market fund.
The Company also provides benefits such as workers’ compensation and disabled employees’ medical care to former or inactive employees after employment but before retirement. The accumulated postemployment benefit obligation was $14 million and $15 million at December 31, 2003 and 2002, respectively.
NOTE 18 - VARIABLE INTEREST ENTITIES
Dayabumi Salak Pratama, Ltd. (“DSPL”) is a variable interest entity formed for the purpose of building and operating a geothermal energy fueled power generating facility in Indonesia. Under a long-term electricity sales contract, DSPL provides power to the Indonesian state-owned electricity company, PT. PLN (Persero) (“PLN”). Unocal Geothermal of Indonesia, Ltd. (“UGI”) owns a 50 percent interest in DSPL and is under contract to administer DSPL operations. DSPL has no employees of its own. DSPL had loans and notes payable totaling $74 million at December 31, 2003. Neither UGI nor the Company has guaranteed DSPL’s debt obligations, which are non-recourse. The Company consolidated DSPL commencing in the third quarter of 2003 in accordance with FASB Interpretation No. 46 (see note 2 for further details). See note 25-Trust Convertible Preferred Securities for discussion of an additional variable interest entity.
NOTE 19 - LONG-TERM DEBT AND CREDIT AGREEMENTS
The following table summarizes the Company’s long-term debt:
(a) Weighted average interest rate at December 31, 2003 and 2002, respectively.
(b) Non-Recourse debt.
(c) Limited-Recourse debt.
At December 31, 2003, the amounts of debt and capital leases maturing in 2004, 2005, 2006, 2007 and 2008 were $248 million, $460 million, $267 million, $110 million and $65 million, respectively.
In 2003, the Company’s consolidated debt, including the current portion, decreased by $125 million. The Company retired $89 million in 9.25% debentures and paid down $10 million of medium-term notes that matured. The Company repurchased $194 million of debt principal through a tender offer, which included $115 million of the 7.20 percent notes due in 2005 and $79 million of the 6.50 percent notes due in 2008. The Company also repurchased $34 million of the 7.35% notes due in 2009, $34 million of the 9.125% debentures due in 2006, $27 million of the 6.375% notes due in 2004 and $26 million of medium-term notes in varying maturities. The Company also repaid $20 million of 6.20% Industrial Development Revenue Bonds due in 2008. In total, the Company paid approximately $35 million pre-tax ($30 million after-tax) in premiums for the early redemption of debt in 2003.
In 1999, the Company contributed fixed-price overriding royalty interests from its working interest shares in certain oil and gas producing properties in the Gulf of Mexico to Spirit LP. In exchange for its overriding royalty contributions, valued at $304 million, the Company received an initial general partnership interest in Spirit LP of approximately 55 percent. An unaffiliated investor contributed $250 million in cash to the partnership in exchange for an initial limited partnership interest of approximately 45 percent. In June, 2003 the Company entered into an agreement to pay the limited partner for its minority interest in Spirit LP, the amount of which was $252 million. In July, 2003 the agreement was executed and the payment was made. In the third quarter of 2003, FASB Interpretation No. 46 would have required the Company to consolidate the limited partner, an unaffiliated investor, which would have resulted in a reclassification of $242 million of minority interests to long-term debt.
These decreases in debt and other financings were partially offset by $205 million drawn under the Overseas Private Investment Corporation (“OPIC”) Financing Agreement, a limited recourse loan, for the first phase of the West Seno project in Indonesia. The Company and its co-venturer completed financing arrangements for a portion of the total costs of the project through two loans arranged with OPIC. One loan is for $300 million and covers the first phase, and the other loan is for $50 million and is for the second phase. The second phase loan will be subject to further due diligence by the lender. The initial draw down of $79 million has a floating rate that is adjusted weekly, which as of December 31, 2003 was set at 1.10 percent. Subsequent 2003 draw downs of $75 million and $51 million carry fixed rates that were 2.41 percent and 2.89 percent, respectively.
At December 31, 2003, the Company had $24 million outstanding on its Azerbaijan limited recourse loan. The Company completed the limited recourse project financing for its separate share of the Azerbaijan International Operating Company Early Oil Project under an International Finance Corporation and European Bank for Reconstruction and Development loan structure in 1998 for up to $77 million. The borrowing bears interest at a margin above London Interbank Offered Rates (“LIBOR”). The lenders’ principal and interest payments are payable only out of the cash flow from the Company’s sales of crude oil from the project.
At December 31, 2003, consolidated debt included $350 million in unsecured senior notes, which bear interest at 7.125 percent and mature in 2011 that relates to the Company’s Pure subsidiary. The notes were issued at a discount to their face value. Neither Unocal nor Union Oil guarantees any of Pure’s debt.
Effective in the third quarter of 2003, FASB Interpretation No. 46 (see note 2 for further details) required the Company to consolidate assets and liabilities and results of operations of DSPL, resulting in the reporting of an additional $74 million as long-term debt on the consolidated balance sheet. Neither UGI nor the Company has guaranteed DSPL’s debt obligations, which are non-recourse.
The Company has two credit facilities in place: a $400 million 364-day credit agreement, which is due to terminate on September 30, 2004 and a $600 million credit agreement due to terminate on October 31, 2006. Borrowings under the bank credit agreements bear interest at a margin above LIBOR and the agreements call for a facility fee on the total commitment. The credit facilities provide for the termination of their loan commitments and require the prepayment of all outstanding borrowings in the event that (1) any person or group becomes the beneficial owner of more than 30 percent of the then outstanding voting stock of Unocal other than in a transaction having the approval of the Company’s board of directors, at least a majority of which are continuing directors, or (2) if continuing directors shall cease to constitute at least a majority of the board. The agreements do not have drawdown restrictions or prepayment obligations in the event of a credit rating downgrade. The interest rates charged on these credit facilities would vary marginally if a change occurred in the Company’s credit rating. Both agreements limit the Company’s debt to equity ratio to 70 percent, with the Company’s convertible preferred securities included as equity in the ratio calculation. The Company had not drawn any funds under either credit facility at year-end 2003.
The Company also has a 3-year $295 million Canadian dollar-denominated non-revolving credit facility with a variable rate of interest. At December 31, 2003, the borrowings under the credit facility translated to $227 million, using applicable foreign exchange rates, compared to $186 million at year-end 2002.
The Company had undrawn letters of credit at year-end 2003 that approximated $44 million. The majority of these letters of credit are maintained for operational needs and are renewed yearly.
NOTE 20 - ACCRUED ABANDONMENT, RESTORATION AND ENVIRONMENTAL LIABILITIES
Effective January 1, 2003, the Company adopted SFAS No. 143 which increased its accrued abandonment and restoration liabilities by $268 million (see note 2 for further detail). At January 1, 2003 and December 31, 2003, the Company had accrued $758 million and $710 million, respectively, in estimated abandonment and restoration costs as liabilities. The decrease in the liability account from January 1, 2003 was primarily due to $86 million associated with assets sold during the year and settlements that totaled $21 million. This was offset by accrued pre-tax accretion expense of $44 million and by $15 million in new abandonment liabilities recorded during the year. There were no material revisions to existing abandonment and restoration liabilities during 2003. The year-end 2003 liability amount represented approximately one-half of the Company’s determinable abandonment and restoration costs adjusted for inflation.
At December 31, 2003 and 2002, the Company’s reserve for environmental remediation obligations totaled $252 million and $245 million, respectively, of which $118 million at year-end 2003 and $113 million at year-end 2002 were included in current liabilities. The reserve, at December 31, 2003 and 2002, included estimated probable future costs of $15 million and $17 million, respectively, for federal Superfund and comparable state-managed multi-party disposal sites; $28 million and $37 million, respectively, for active sites owned and/or controlled by the Company and utilized in its present operations; $99 million and $104 million, respectively, for formerly operated sites for which the Company has remediation obligations and sites related to businesses or operations that have been sold with contractual remediation or indemnification obligations; and $110 million and $87 million, respectively, for Company-owned or controlled sites where facilities have been closed or operations shut down.
NOTE 21 - OTHER FINANCIAL INFORMATION
The consolidated balance sheet included the following:
Pension and other employee benefits included $91 million and $103 million at December 31, 2003 and 2002, respectively, to recognize the minimum pension liability for the Company’s U.S. Qualified Retirement Plan. These amounts reflect the excess of the accumulated benefit obligation for vested current and former employees over the fair value of plan assets. See note 17 for a full discussion of the minimum pension liability for the Company’s U.S. Qualified Retirement Plan.
NOTE 22 - ADVANCE SALES OF NATURAL GAS
The Company entered into a long-term fixed price natural gas sales contract for the delivery of approximately 72 billion cubic feet of gas over a ten-year period beginning in January 1999 and ending in December 2008. In January 1999, the Company received a non-refundable payment of approximately $120 million pursuant to the contract. The Company will also receive a fixed monthly reservation fee over the life of the contract. The Company entered into a ten-year natural gas price swap agreement, which effectively refloated the fixed price that the Company received under the long-term natural gas sales contract. The Company did not dedicate a portion of its natural gas reserves to the contract and it has the option to satisfy contract delivery requirements with natural gas purchased from third parties. Accordingly, the obligation associated with the future delivery of the natural gas has been recorded as deferred revenue and will be amortized into revenue as scheduled deliveries of natural gas are made throughout the contract period. Of the remaining unamortized balance at year-end 2003, approximately $49 million related to deliveries scheduled to be made in the years 2005 through 2008 and was recorded in other deferred credits and liabilities on the consolidated balance sheet. Approximately $12 million was included in other current liabilities on the consolidated balance sheet, representing deliveries to be made in 2004. At December 31, 2003, the Company had in place an irrevocable surety bond in the amount of $80 million and letters of credit in the amount of $16 million, securing its performance under the sales contract.
NOTE 23 - MINORITY INTERESTS
At December 31, 2003, the Company’s minority interests on the consolidated balance sheet were $39 million, a decrease of $236 million from 2002. This decrease was primarily due to the payment of the limited partner’s minority interest in Spirit LP in July 2003 for $252 million. Spirit LP was formed in 1999 when the Company contributed fixed-price overriding royalty interests, valued at $304 million, from its working interest shares in certain oil and gas producing properties in the Gulf of Mexico to the partnership. An unaffiliated investor contributed $250 million in cash to the partnership and received a priority allocation of profits and cash distributions.
At December 31, 2003, the $39 million reflected in minority interests included amounts relating to the outside interests of certain oil and gas, carbon, and real estate entities. Along with these entities, the amount in minority interests included the outside interest in DSPL, which was consolidated in the third quarter of 2003 as required by FASB Interpretation No. 46 (see notes 2 and 18 for further details).
NOTE 24 - COMMITMENTS AND CONTINGENCIES
The Company has certain contingent liabilities with respect to material existing or potential claims, lawsuits and other proceedings, including those involving environmental matters, taxes, guarantees and other matters, certain of which are discussed more specifically below. The Company accrues liabilities when it is probable that future costs will be incurred and such costs can be reasonably estimated. Such accruals are based on developments to date, the Company’s estimates of the outcomes of these matters and its experience in contesting, litigating and settling other matters. As the scope of the liabilities becomes better defined, there will be changes in the estimates of the future costs, which could have a material effect on the Company’s future results of operations and financial condition or liquidity.
Environmental matters
The Company continues to move forward to address environmental issues for which it is responsible. The Company, in cooperation with regulatory agencies and others, follows procedures that it has established to identify and cleanup contamination associated with its past operations. The Company is subject to loss contingencies pursuant to federal, state, local and foreign environmental laws and regulations. These include existing and possible future obligations to investigate the effects of the release or disposal of certain petroleum, chemical and mineral substances at various sites; to remediate or restore these sites; to compensate others for damage to property and natural resources, for remediation and restoration costs and for personal injuries; and to pay civil penalties and, in some cases, criminal penalties and punitive damages. These obligations relate to sites owned by the Company or others and are associated with past and present operations, including sites at which the Company has been identified as a potentially responsible party (“PRP”) under the federal Superfund laws and comparable state laws. Liabilities are accrued when it is
probable that future costs will be incurred and such costs can be reasonably estimated. However, in many cases, investigations are not yet at a stage where the Company is able to determine whether it is liable or, even if liability is determined to be probable, to quantify the liability or estimate a range of possible exposure. In such cases, the amounts of the Company’s liabilities are indeterminate due to the potentially large number of claimants for any given site or exposure, the unknown magnitude of possible contamination, the imprecise and conflicting engineering evaluations and estimates of proper clean-up methods and costs, the unknown timing and extent of the corrective actions that may be required, the uncertainty attendant to the possible award of punitive damages, the recent judicial recognition of new causes of action, the present state of the law, which often imposes joint and several and retroactive liabilities on PRPs, the fact that the Company is usually just one of a number of companies identified as a PRP, or other reasons.
As disclosed in note 20, at December 31, 2003, the Company had accrued $252 million for estimated future environmental assessment and remediation costs at various sites where liabilities for such costs are probable and reasonably estimable. The Company may also incur additional liabilities in the future at sites where remediation liabilities are probable but future environmental costs are not presently reasonably estimable because the sites have not been assessed or the assessments have not advanced to the stage where costs are reasonably estimable. At those sites where investigations or feasibility studies have advanced to the stage of analyzing feasible alternative remedies and/or ranges of costs, the Company estimates that it could incur possible additional remediation costs aggregating approximately $205 million. The amount of such possible additional costs reflects the aggregate of the high ends of the ranges of costs of feasible alternatives identified by the Company for those sites with respect to which investigation or feasibility studies have advanced to the stage of analyzing such alternatives. However, such estimated possible additional costs are not an estimate of the total remediation costs beyond the amounts reserved, because there are sites where the Company is not yet in a position to estimate all, or in some cases any, possible additional costs. Both the amounts reserved and estimates of possible additional costs may change in the near term, and in some cases could change substantially, as additional information becomes available regarding the nature and extent of site contamination, required or agreed-upon remediation methods and other actions by government agencies and private parties.
During 2003, cash payments of $85 million were applied against the reserves and $92 million in provisions were added to the reserves. Possible additional remediation costs decreased by $40 million in 2003. The accrued costs and the possible additional costs are shown below for four categories of sites:
The time frames over which the amounts included in the reserve may be paid extend from the near term to several years into the future. The sites included in the above categories are in various stages of investigation and remediation; therefore, the related payments against the existing reserve will be made in future periods. Also, some of the work is dependent upon reaching agreements with regulatory agencies and/or other third parties on the scope of remediation work to be performed, who will perform the work, the timing of the work, who will pay for the work and other factors that may have an impact on the timing of the payments for amounts included in the reserve. For some sites, the remediation work will be performed by other parties, such as the current owners of the sites, and the Company has a contractual agreement to pay a share of the remediation costs. For these sites, the Company generally has less control over the timing of the work and consequently the timing of the associated payments. Based on available information, the Company estimates that the majority of the amounts included in the reserve will be paid within the next three to five years.
At the sites where the Company has contractual agreements to share remediation costs with third parties, the reserve reflects the Company’s estimated shares of those costs. In many of the oil and gas sites, remediation cost sharing is included in joint venture agreements that were made with third parties during the original operation of the sites. In many cases where the Company sold facilities or a business to a third party, sharing of remediation costs for those sites may be included in the sales agreement.
Contamination at the sites of the “Superfund and similar sites” category was the result of the disposal of substances at these sites by one or more PRPs. Contamination of these sites could be from many sources, of which the Company may be one. The Company has been notified that it is a PRP at the sites included in this category. At the sites where the Company has not denied liability, the Company’s contribution to the contamination at these sites was primarily from operations identified below.
The “Active Company facilities” category includes oil and gas fields and mining operations. The oil and gas sites are primarily contaminated with crude oil, oil field waste and other petroleum hydrocarbons. Contamination at the active mining sites was principally the result of the impact of mined material on the groundwater and/or surface water at these sites.
The “Company facilities sold with retained liabilities and former Company-operated sites” and “Inactive or closed Company facilities” categories include former Company refineries, transportation and distribution facilities and service stations. The required remediation of these sites is mainly for petroleum hydrocarbon contamination as the result of leaking tanks, pipelines or other equipment or impoundments that were used in these operations. Also, included in these categories are former oil and gas fields that the Company no longer operates. In most cases, these sites are contaminated with crude oil, oil field waste and other petroleum hydrocarbons. Contamination at other sites in these categories of sites was the result of former industrial chemical and polymers manufacturing and distribution facilities, agricultural chemical retail businesses and ferromolybdenum production operations.
Superfund and similar sites - Included in this category of sites are:
• The McColl site in Fullerton, California
• The Operating Industries site in Monterey Park, California
• The Casmalia Waste site in Casmalia, California
At December 31, 2003, the Company had received notifications from the U.S. Environmental Protection Agency (“EPA”) that the Company may be a PRP at 26 sites and may share certain liabilities at these sites. Of the total, six sites are under investigation and/or litigation and the Company’s potential liability is not presently determinable and for one site, the Company has denied responsibility. At one site the Company’s potential liability appears to be de minims. Of the remaining 18 sites, where the Company has concluded that liability is probable and to the extent costs can be reasonably estimated, a reserve of $11 million has been established for future remediation and settlement costs.
Various state agencies and private parties had identified 20 other similar PRP sites. Six sites are under investigation and/or litigation and the Company’s potential liability is not presently determinable and at three sites the Company’s potential liability appears to be de minimis. Where the Company has concluded that liability is probable and to the extent costs can be reasonably estimated at the remaining 11 sites, a reserve of $4 million has been established for future remediation and settlement costs.
The sites discussed above exclude 123 sites where the Company’s liability has been settled, or where the Company has no evidence of liability and there has been no further indication of liability by government agencies or third parties for at least a 12-month period.
The Company does not consider the number of sites for which it has been named a PRP as a relevant measure of liability. Although the liability of a PRP is generally joint and several, the Company is usually just one of numerous companies designated as a PRP. The Company’s ultimate share of the remediation costs at those sites often is not determinable due to many unknown factors. The solvency of other responsible parties and disputes regarding responsibilities may also impact the Company’s ultimate costs.
Active Company facilities - Included in this category are:
• The Molycorp molybdenum mine in Questa, New Mexico
• The Molycorp lanthanide facility in Mountain Pass, California
• Alaska oil and gas properties
The Company has a reserve of $28 million for estimated future costs of remedial orders, corrective actions and other investigation, remediation and monitoring obligations at certain operating facilities and producing oil and gas fields. The Company recorded provisions of $7 million during 2003 for the “Active Company facilities” category of sites. The provisions were primarily for the remedial investigation and feasibility study (RI/FS) being performed at a molybdenum mine located in Questa, New Mexico, that is owned by the Company’s Molycorp, Inc. (“Molycorp”) subsidiary. Molycorp has been working closely with the U.S. Environmental Protection Agency and the State of New Mexico in conducting the RI/FS at the mine during the year. The RI/FS is being performed to determine if past mining operations have had an adverse impact on the environment. Numerous additions and changes to the RI/FS scope have been required by the agencies, which will require a higher level of effort than originally projected.
The Company made payments of $13 million for this category of sites in 2003.
Company facilities sold with retained liabilities and former Company-operated sites - Company facilities sold with retained liabilities include:
• West Coast refining, marketing and transportation sites
• Auto/truckstop facilities in various locations in the U.S.
• Industrial chemical and polymer sites in the South, Midwest and California
• Agricultural chemical sites in the West and Midwest.
In each sale, the Company retained a contractual remediation or indemnification obligation and is responsible only for certain environmental problems that resulted from operations prior to the sale. The reserve represents estimated future costs for remediation work: identified prior to the sale of these sites; included in negotiated agreements with the buyers of these sites where the Company retained certain levels of remediation liabilities; and/or identified in subsequent claims made by buyers of the properties. Former Company-operated sites include service stations, distribution facilities and oil and gas fields that were previously operated but not owned by the Company.
The Company has an aggregate reserve of $99 million for this group of sites. During 2003, provisions of $46 million for the “Company facilities sold with retained liabilities and former Company-operated sites” category were recorded. These provisions included the estimated cleanup costs for oil fields located in Michigan and California that were formerly operated by the Company. The estimated costs are based on assessments recently performed at the sites, higher than anticipated volumes of contaminated soil at existing sites and higher remediation costs for soil excavation and disposal than originally anticipated. The provisions for this category of sites were also the result of revised remediation cost estimates that were identified during 2003 for service station sites and distribution facilities formerly operated by the Company.
Provisions were also recorded for auto/truckstop sites that were sold by the Company in 1993. In December 2003, an agreement was reached with the owner of certain of these auto/truckstops indemnifying the Company from future remediation liabilities and obligations related to these sites in exchange for a cash payment and payment for insurance coverage for unforeseen future environmental exposure that may arise from contamination that existed prior to the original sale of the sites. The agreement was finalized in January 2004. In addition, the Company received revised remediation cost estimates from the purchaser of service stations, bulk plants, terminals, refineries and pipelines that were part of the Company’s former West Coast refining, marketing and transportation assets sold in 1997.
Payments of $53 million were made during 2003 for sites in this category.
Inactive or closed Company facilities - The major sites in this category are:
• The Guadalupe oil field on the central California coast
• The Molycorp Washington and York facilities in Pennsylvania
• The Beaumont Refinery in Texas.
A reserve of $110 million has been established for these types of facilities. During 2003, the Company accrued $38 million related to sites in this category primarily for the Guadalupe oil field and for remediation projects at the Beaumont Refinery. For the Guadalupe oil field site, it was determined that contaminated soil excavated from the site will be taken to an offsite landfill for disposal. The soil is contaminated with diluent, a kerosene-like additive used in the field’s former operations. Previously, the Company had planned to remediate the soil on-site; however, a preliminary draft report for the ecological risk study being conducted indicates that on-site remediation is not viable. The provisions recorded for the site include the costs for the offsite disposal alternative. The provisions recorded for the Guadalupe oil field also include estimated costs for remediation work that is ongoing at the site. This work includes groundwater monitoring, operation and maintenance of remedial systems, restoration, site assessment and regulatory agency oversight and permitting procedures. The provisions for these costs are based on data from various studies and assessments that have been completed for the site in conjunction with data provided by the project management system the Company has in place.
A provision was also recorded for the Company’s former Beaumont, Texas refinery. The Company has been working with the Texas Commission on Environmental Quality (“TCEQ”) to develop plans for closing impoundments used in the site’s former operations and for other remediation projects. In 2003, the Company recorded a provision for the revised estimated costs of the impoundment closure plan based on the TCEQ initial draft permit that was issued for the site.
Payments of $17 million were made during 2003 for sites in this category.
The Company is subject to federal, state and local environmental laws and regulations, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”), as amended, the Resource Conservation and Recovery Act (“RCRA”) and laws governing low level radioactive materials. Under these laws, the Company is subject to existing and/or possible obligations to remove or mitigate the environmental effects of the disposal or release of certain chemical, petroleum and radioactive substances at various sites. Corrective investigations and actions pursuant to RCRA and other federal, state and local environmental laws are being performed at the Company’s facility in Beaumont, Texas, a former agricultural chemical facility in Corcoran, California, and Molycorp’s facility in Washington, Pennsylvania. In addition, Molycorp is required to decommission its Washington and York facilities in Pennsylvania pursuant to the terms of their respective radioactive source materials licenses and decommissioning plans.
The Company also must provide financial assurance for future closure and post-closure costs of its RCRA-permitted facilities and for decommissioning costs at facilities that are under radioactive source materials licenses. Pursuant to a 1998 settlement agreement between the Company and the State of California (and the subsequent stipulated judgment entered by the Superior Court), the Company must provide financial assurance for anticipated costs of remediation activities at its inactive Guadalupe oil field. Also, pursuant to a 1995 settlement agreement between Molycorp and the California Department of Toxic Substances Control (and subsequent final judgment entered by the Superior Court), the Company must provide financial assurance for anticipated costs of disposing of certain wastes, as well as closing facilities associated with the handling of those wastes, at Molycorp’s Mountain Pass, California, facility. As previously discussed, remediation reserves for these sites are included in the “Active Company facilities” and “Inactive or closed Company facilities” categories and total $113 million at December 31, 2003. At those sites where investigations or feasibility studies have advanced to the stage of analyzing alternative remedies and/or ranges of costs, the Company estimates that it could incur possible additional remediation costs aggregating approximately $55 million. Although any possible additional costs for these sites are likely to be incurred at different times and over a period of many years, the Company believes that these obligations could have a material adverse effect on the Company’s results of operations but are not expected to be material to the Company’s consolidated financial condition or liquidity.
The total environmental remediation reserve recorded on the consolidated balance sheet represents the Company’s estimates of assessment and remediation costs based on currently available facts, existing technology and presently enacted laws and regulations. The remediation cost estimates, in many cases, are based on plans recommended to the regulatory agencies for approval and are subject to future revisions. The ultimate costs to be incurred could exceed the total amounts reserved. The reserve will be adjusted as additional information becomes available regarding the nature and extent of site contamination, required or agreed-upon remediation methods and other actions by government agencies and private parties. Therefore, amounts reserved may change substantially in the near term.
The Company maintains insurance coverage intended to reimburse the cost of damages and remediation related to environmental contamination resulting from sudden and accidental incidents under current operations. The purchased coverages contain specified and varying levels of deductibles and payment limits. Although certain of the Company’s contingent legal exposures enumerated above are uninsurable either due to insurance policy limitations, public policy or market conditions, management believes that its current insurance program significantly reduces the possibility of an incident causing a material adverse financial impact to the Company.
Certain Litigation and Claims
Agrium Litigation:
In June 2002, a lawsuit was filed against the Company by Agrium Inc., a Canadian corporation, and Agrium U.S. Inc., its U. S. subsidiary, in the Superior Court of the State of California for the County of Los Angeles (Agrium U.S. Inc. and Agrium Inc. v. Union Oil Company of California, Case No. BC275407) (the “Agrium Claim”). Simultaneously, the Company filed suit against the Agrium entities (“Agrium”) in the U.S. District Court for the Central District of California (Union Oil Company of California v. Agrium, Inc., Case No. 02-04518 NM) (the “Company Claim”). The Company subsequently removed the Agrium Claim to the U.S. District Court for the Central District of California (Case No. 02-04769 NM). The federal court has since remanded the Agrium Claim to the California Superior Court. In addition, the Company has initiated arbitration concerning the Gas Purchase and Sale Agreement (“GPSA”) between the Company and Agrium U.S. Inc. (AAA Case No. 70 198 00539 02) (the “Arbitration”).
The Agrium Claim alleges numerous causes of action relating to Agrium’s 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 the GPSA. Agrium alleges that the Company misrepresented the amount of natural gas reserves available for sale to the plant as of the closing of the transaction and that the Company has failed to develop additional natural gas 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 in the Purchase and Sale Agreement for the plant (the “PSA”) 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.
In September 2002, Agrium amended its complaint to add allegations that the Company breached certain conditions of the September 2000 closing, breached certain indemnification obligations, and violated the pertinent health and safety code. Agrium also asked for recission of the sale of the fertilizer plant, in addition, or as an alternative, to money damages. In addition, Agrium seeks a declaration by the arbitral panel that has been convened (see below) that natural gas from Unocal’s Ninilchik, Happy Valley fields “or elsewhere” should be delivered to the plant to meet Unocal’s alleged obligations under the GPSA.
In the Company Claim, 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 $17 million plus interest accrued
subsequent to May 2002. Unocal is also seeking over $900,000 in reliability bonuses due under the GPSA and reimbursement of over $5 million in royalties paid to the State of Alaska.
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. On July 16, 2003, the court approved an agreed stipulation between the parties to submit all issues under the GPSA to arbitration. The arbitration proceedings are scheduled to commence May 24, 2004. Discovery is now proceeding.
Petrobangla Claim:
In July 2002, the Company’s subsidiary Unocal Bangladesh Blocks Thirteen and Fourteen, Ltd. (“Unocal Blocks 13 and 14 Ltd.”) received a letter from the Bangladesh Oil, Gas & Mineral Corporation (“Petrobangla”) claiming, on behalf of the Bangladesh government and Petrobangla, compensation allegedly due in the amount of $685 million for 246 BCF of recoverable natural gas allegedly “lost and damaged” in a 1997 blowout and ensuing fire during the drilling by Occidental Petroleum Corporation (known at that time in Bangladesh as Occidental of Bangladesh Ltd.) (“OBL”), as operator, of the Moulavi Bazar #1 (“MB #1”) exploration well on the Blocks 13 and 14 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 contractor’s 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 1998 Supplemental Agreement to the PSC (the “Supplemental Agreement”), 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 (“Unocal Bangladesh”)) of entitlement to the recovery of costs incurred in the drilling of the MB #1 and 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 present or development is not feasible 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 Unocal Blocks 13 and 14 Ltd. has advised Petrobangla that no additional compensation is warranted. By Writ Petition Affidavit dated March 24, 2003, a concerned citizen filed suit in the Bangladesh lower court (Alam v. Bangladesh, Petrobangla, Department of Environment, and Unocal Bangladesh, Ltd., Supreme Court of Bangladesh, High Court Division, Writ Petition No. 2461 of 2003) on the basis of the MB #1 blowout. The Company was notified of the suit on May 26, 2003 when it received the court’s order to show cause why the Supplemental Agreement should not be declared illegal and cancelled on account of its having been executed without lawful authority, and why Unocal Bangladesh should not be directed to stop exploration until it compensates for the MB#1 blowout. No hearing is currently scheduled on the matter, and the Company believes the action is not well founded.
Nuevo Energy Claim:
In March 2003, the Company received a letter from Nuevo Energy Company regarding a contingent payment for the year 2002 owed by Nuevo to the Company under the terms of the 1996 Asset Purchase Agreement pursuant to which Nuevo purchased substantially all of the Company’s operating California oil and gas properties. Notwithstanding that Nuevo had notified the Company in January 2003 of its estimate of the payment for 2002, Nuevo now claims that the long-standing calculation methodology for this payment was incorrect, that no payment should be due for 2002, and that the payment made for 2001 should be refunded. The Company disputes Nuevo’s new position. On June 30, 2003, Nuevo filed suit against Unocal in the U.S. District Court for the Central District of California, Case No. 03-4664 (RCx). Nuevo seeks $10.8 million, the amount Nuevo alleges it paid Unocal in error. Nuevo also seeks a declaratory judgment regarding its right to take deductions in calculating the contingent payment in the future. Unocal has counterclaimed, seeking in excess of $16 million for amounts owed from 2002 under the contingent payment agreement and for a
declaratory judgment regarding the rights and relations of Unocal and Nuevo under that agreement. The case is scheduled to go to trial May 11, 2004.
Tax matters
The Company believes it has adequately provided in its accounts for tax items and issues not yet resolved. Several prior material tax issues are unresolved. Resolution of these tax issues impacts not only the year in which the items arose, but also the Company’s tax situation in other tax years. With respect to 1979-1994 taxable years, all issues raised for these years have now been tentatively settled with the Appeals division of the Internal Revenue Service (“IRS”) as well as the Tax Court, including the carryback of a 1993 net operating loss (“NOL”) to tax year 1984 and resultant credit adjustments. The 1993 NOL resulted from certain specified liability losses described in Internal Revenue Code Section 172. Since the audit of the 1979-1994 taxable years resulted in a net overpayment of income taxes for the period, the Joint Committee on Taxation of the U.S Congress must review the claim. Once notification from the Joint Committee is received, taxable years 1979-1994 will be effectively closed as a single package, pending entry of final decisions in Tax Court for the docketed years, to assure that interest is properly computed under the complex rules, which govern netting of interest. All such developments have been considered in the Company’s accounts. The 1995-1997 taxable years are before the Appeals division of the IRS. The 1998- 2001 taxable years are now before the Exam division of the IRS.
Guarantees Related to Assets or Obligations of Third Parties
The Company has agreed to indemnify certain third parties for particular future remediation costs that may be incurred for properties held by these parties. The guarantees were established when the Company either leased property from or sold property to these third parties. The properties may or may not have been contaminated by various Company operations. Where it has been or will be determined that the Company is responsible for contamination, the guarantees require the Company to pay the costs to remediate the sites to specified cleanup levels or to levels that will be determined in the future.
The maximum potential amount of future payments that the Company could be required to make under these guarantees is indeterminate primarily due to the following: the indefinite term of the majority of these guarantees; the unknown extent of possible contamination; uncertainties related to the timing of the remediation work; possible changes in laws governing the remediation process; the unknown number of claims that may be made; changes in remediation technology; and the fact that most of these guarantees lack limitations on the maximum potential amount of future payments.
The Company has accrued probable and reasonably estimable assessment and remediation costs for the locations covered under these guarantees. These amounts are included in the “Company facilities sold with retained liabilities and former Company-operated sites” category of the Company’s reserve for environmental remediation obligations. At December 31, 2003, the reserve for this category totaled $99 million. For those sites where investigations or feasibility studies have advanced to the stage of analyzing feasible alternative remedies and/or ranges of costs, the Company estimates that it could incur possible additional remediation costs aggregating approximately $75 million. See the discussion elsewhere in this footnote for additional information regarding this category.
The Company has guaranteed the debt of certain joint ventures accounted for by the equity method. The majority of this debt matures ratably through the year 2014. The maximum potential amount of future payments the Company could be required to make is approximately $19 million.
In the ordinary course of business, the Company has agreed to indemnify cash deficiencies for certain domestic pipeline joint ventures, which the Company accounts for on the equity method. These guarantees are considered in the Company’s analysis of overall risk. Since most of these agreements do not contain spending caps, it is not possible to quantify the amount of maximum payments that may be required. Nevertheless, the Company believes the payments would not have a material adverse impact on its financial condition or liquidity.
Financial Assurance for Unocal Obligations
In the normal course of business, the Company has performance obligations that are secured, in whole or in part, by surety bonds or letters of credit. These obligations primarily cover self-insurance, site restoration, dismantlement and other programs where governmental organizations require such support. These surety bonds and letters of credit are issued by financial institutions and are required to be reimbursed by the Company if drawn upon. At December 31, 2003, the Company had obtained various surety bonds for approximately $191 million. These surety bonds included a bond for $80 million securing the Company’s performance under a fixed price natural gas sales contract for the delivery of 72 billion cubic feet of gas over a ten-year period that began in January of 1999 and will end in December of 2008 and approximately $111 million in various other routine performance bonds held by local, city, state and federal agencies. The Company also had obtained approximately $44 million in standby letters of credit at December 31, 2003, of which $16 million represented additional collateral related to the aforementioned fixed price natural gas sales contract. The Company has entered into indemnification obligations in favor of the providers of these surety bonds and letters of credit.
The Company has various other guarantees for approximately $553 million. Approximately $134 million of the $553 million in guarantees represent financial assurance given by the Company on behalf of its Molycorp subsidiary relating to permits covering operations and discharges from its Questa, New Mexico, molybdenum mine. The Company’s financial assurance is for the completion of temporary closure plans (required only upon cessation of operations) and other obligations required under the terms of the permits. The costs associated with the financial assurance are based on estimations provided by agencies of the state of New Mexico.
Guarantees for approximately $333 million of the $553 million would require the Company to obtain a surety bond or a letter of credit or establish a trust fund if its credit rating were to drop below investment grade-that is BBB- or Baa3 from Standard & Poor’s Ratings Services and Moody’s Investors Service, Inc., respectively.
Approximately $155 million of the surety bonds, letters of credit and other guarantees that the Company is required to obtain or issue reflect obligations that are already included on the consolidated balance sheet in other current liabilities and other deferred credits. The surety bonds, letters of credit and other guarantees may also reflect some of the possible additional remediation liabilities discussed earlier in this note.
Other matters
The Company has a lease agreement relating to the Discoverer Spirit deepwater drillship, with a current minimum daily rate of approximately $226,000. The future remaining minimum lease payment obligation was approximately $140 million at December 31, 2003. The contract will expire on September 18, 2005.
The Company also has other contingent liabilities with respect to litigation, claims and contractual agreements arising in the ordinary course of business. On the basis of management’s assessment of the ultimate amount and timing of possible adverse outcomes and associated costs, none of such matters is presently expected to have a material adverse effect on the Company’s consolidated financial condition, liquidity or results of operations.
NOTE 25 - TRUST CONVERTIBLE PREFERRED SECURITIES
In 1996, Unocal exchanged 10,437,873 newly issued 6 ¼% trust convertible preferred securities of Unocal Capital Trust, a Delaware statutory trust (the “Trust”), for shares of a then-outstanding issue of convertible preferred stock. Unocal acquired the convertible preferred securities, which had an aggregate liquidation value of $522 million, from the Trust, together with 322,821 common securities of the Trust, which had an aggregate liquidation value of $16 million, in exchange for $538 million principal amount of 6 ¼% convertible junior subordinated debentures of Unocal. The common securities of the Trust, which have been retained by Unocal, and the convertible preferred securities represent undivided beneficial interests in the debentures, which constitute substantially all of the assets of the Trust. The numbers of convertible preferred securities outstanding were 10,437,105 on December 31, 2003 and December 31, 2002.
The convertible preferred securities have a liquidation value of $50 per security and are convertible into shares of Unocal common stock at a conversion price of $42.56 per share, subject to adjustment upon the occurrence of certain events. Distributions on the convertible preferred securities are cumulative at an annual rate of 6.25 percent of their liquidation amount and are payable quarterly in arrears on March 1, June 1, September 1 and December 1 of each year to the extent that the Trust receives interest payments on the debentures, which payments are subject to deferral by Unocal under certain circumstances.
The debentures mature on September 1, 2026, and may be redeemed, in whole or in part, at the option of Unocal at a redemption price equal to 101.875 percent (since September 1, 2003), of the principal amount redeemed, declining annually to 100 percent of the principal amount redeemed on or after September 1, 2006, plus accrued and unpaid interest thereon to the redemption date. The debentures, and hence the convertible preferred securities, may become redeemable at the option of Unocal upon the occurrence of certain special events or restructuring transactions.
Upon repayment of the debentures by Unocal, whether at maturity, upon redemption or otherwise, the proceeds thereof must immediately be applied to redeem a corresponding amount of the convertible preferred securities and the common securities of the Trust.
The Trust is accounted for as a 100-percent-owned consolidated finance subsidiary of Unocal, with the debentures and payments thereon by Unocal to the Trust eliminated in the consolidated financial statements. The payment obligations of the Trust under the convertible preferred securities are unconditionally guaranteed on a subordinated basis by Unocal. Such guarantee, when taken together with Unocal’s obligations under the debentures and the indenture pursuant to which the debentures were issued and its obligations under the amended and restated declaration of trust governing the Trust, provides a full and unconditional guarantee by Unocal of the Trust’s obligations under the convertible preferred securities.
Pursuant to FASB Interpretation No. 46, “Consolidation of Variable Interest Entities,” as revised in December 2003, the Company will be required to deconsolidate the Trust in the first quarter of 2004. As a result, the $522 million obligation for the convertible preferred securities will be removed from the consolidated balance sheet and replaced by a non-current liability for the $538 million in 6-1/4% convertible junior subordinated debentures of Unocal payable to the Trust. In addition, the Company will also record its $16 million investment in the Trust in investments and long-term receivables-net on the consolidated balance sheet. Interest payments on the debentures will be recorded as interest expense on the consolidated earnings statement in 2004. See note 2 for additional information regarding the Trust and the accounting change.
NOTE 26 - CAPITAL STOCK
Common Stock
Authorized - 750,000,000
$1.00 Par value per share
(a) net of cancellations
At December 31, 2003, there were approximately 12.3 million shares reserved for the conversion of Unocal Capital Trust convertible preferred securities, 22.6 million shares for the Company’s employee benefit plans and Directors’ plans and 2.6 million shares for the Company’s Dividend Reinvestment and Common Stock Purchase Plan.
Treasury Stock - In January 1998, the Board of Directors extended the repurchase program, which had authorized the repurchase of $400 million of common stock in 1996, and authorized management to repurchase up to an additional $200 million of common stock. At December 31, 2003, the Company held 10,622,784 common shares as treasury stock at a cost of $411 million.
Preferred Stock - The Company has authorized 100,000,000 shares of preferred stock with a par value of $0.10 per share. No shares of preferred stock were issued at December 31, 2003, 2002 or 2001. See “Stockholder Rights Plan” below with respect to shares of preferred stock reserved for issuance.
Stockholder Rights Plan - In 2000, the Board of Directors adopted a new stockholder rights plan (the “2000 Rights Plan”) to replace the 1990 Rights Plan. The Board declared a dividend of one preferred share purchase right (“Right”) for each share of common stock outstanding, which was paid to stockholders of record on January 29, 2000, when the rights outstanding under the 1990 Rights Plan expired. The Board also authorized the issuance of one Right for each common share issued after January 29, 2000, and prior to the earlier of the date on which the Rights become exercisable, the redemption date or the expiration date. Until the Rights become exercisable, as described below, the outstanding Rights trade with, and will be inseparable from, the common stock and will be evidenced only by certificates or book-entry credits that represent shares of common stock. The Board of Directors has designated and reserved 5,000,000 shares of preferred stock as Series B Junior Participating Preferred Stock (“Series B preferred stock”) in connection with the 2000 Rights Plan. The Series B preferred stock replaces the Series A preferred stock that was designated and reserved under the 1990 Rights Plan.
The 2000 Rights Plan, as amended through 2003, provides that in the event any person or group of affiliated persons (a) becomes, or (b) commences a tender offer or exchange offer pursuant to which such person or group would become, an “acquiring person” by virtue of obtaining the beneficial ownership of 15 percent or more (30 percent or more in the case of “Qualified Institutional Investors”) of the outstanding common shares, each Right (other than Rights held by the acquiring person) will be exercisable on and after the close of business on the tenth day or the tenth business day following the public announcement of such events, respectively, unless the Rights are redeemed by the Board of Directors, to purchase one one-hundredth of a share of Series B preferred stock for $180. If such a person or group becomes such an acquiring person, each Right (other than Rights held by the acquiring person) will be exercisable to purchase, for $180, shares of common stock with a market value of $360, based on the market price of the common stock prior to such acquisition.
If the Company is acquired in a merger or similar transaction following the date the Rights become exercisable, each Right (other than Rights held by the acquiring person) will become exercisable to purchase, for $180, shares of the acquiring corporation with a market value of $360, based on the market price of the acquiring corporation’s stock prior to such merger. The Board of Directors may reduce the 15 percent beneficial ownership threshold to not less than 10 percent.
The Rights will expire on January 29, 2010, unless previously redeemed by the Board of Directors, which the Board may do, at a price of $.001 per Right, at any time before any person or group becomes an acquiring person. The Rights do not have voting or dividend rights and, until they become exercisable, have no diluting effect on the earnings per share of the Company.
NOTE 27 - LOANS TO CERTAIN OFFICERS AND KEY EMPLOYEES
In March 2000, the Company entered into loan agreements with ten of its officers pursuant to the Company’s 2000 Executive Stock Purchase Program (the “Program”). The Program was approved by the Board of Directors of the Company and by the Company’s stockholders at the Annual Stockholders meeting in May 2000. The loans were granted to the officers to enable them to purchase shares of Company stock in the open market. The loans, which except under certain limited circumstances are full recourse to the officers, mature on March 16, 2008, and bear interest at the rate of 6.8 percent per annum. The balance of the loans under this Program, including accrued interest, totaled $27 million at December 31, 2003 and $35 million at December 31, 2002, and was reflected as a reduction to stockholders’ equity on the consolidated balance sheet. During 2003, accrued interest of $2 million was offset by payments from the officers of $10 million.
The Company’s Pure subsidiary also had a loan program for certain of its officers and key employees, with a balance of $2 million at December 31, 2002. These loans were repaid during 2003.
NOTE 28 - STOCK-BASED COMPENSATION PLANS
The Company has adopted incentive programs for executives, directors and certain employees to provide incentives and rewards to strengthen their commitment to maximizing the profitability of the Company and increasing stockholder value.
The 1998 Management Incentive Program and the Management Incentive Program of 1991 authorized up to 8.75 million and 11 million shares of common stock, respectively, for stock options, performance stock options, restricted stock and performance share awards. The Union Oil Restricted Stock Plan authorized 0.4 million shares of common stock for restricted stock awards. The Unocal Stock Option Plan and the Special Stock Option Plan of 1996 authorized up to 8 million and 1.1 million shares of common stock, respectively, for stock option awards. The Directors’ Restricted Stock Units Plan authorized the issuance of up to 300,000 shares of common stock and the 2001 Director’s Deferred Compensation and Stock Award Plan authorized the issuance of up to 500,000 shares of common stock.
In connection with the Pure acquisition, on October 30, 2002, employee nonqualified stock options to acquire Pure stock (that were issued by Pure and its predecessors) became fully vested stock options to acquire Unocal common stock; options to acquire a total of 2,481,774 shares with a weighted average exercise price of $18.50 and a weighted average remaining life of 6 years were outstanding at December 31, 2003. Most of the Pure employee stock options were issued under Pure’s 1999 incentive Plan. No further awards will be made under the Pure plans.
All employee and director stock options are nonqualified with a maximum term of ten years. Except for certain stock options granted under Pure’s 1999 Incentive Plan that were granted at prices below fair market value on the grant date, the exercise price for options may not be less than the fair market value of the common stock on the grant date. Director options vest ratably over three years for initial grants and over two years for annual grants. Employee options generally vest over a three-year period at a rate of 50 percent the first year and 25 percent per year in each of the two succeeding years.
Restrictions may be imposed for a period of five years on certain shares acquired through the exercise of options granted after 1990 under the Management Incentive Program of 1991 and the Management Incentive Program of 1998.
The Compensation Committee of the Company’s Pure subsidiary may approve the extension of a loan by the Company to assist in paying the exercise price of an option and/or any tax required by law to be withheld upon exercise of an option assumed by Unocal Corporation in connection with the acquisition.
Stock options generally cease to vest upon termination of employment. Vested options generally may be exercised for up to three years (depending upon the terms of the individual award agreements), or the original expiration date, whichever is earlier, from the date of death, disability, or termination of employment other than for cause or resignation. A majority of the options assumed by Unocal in connection with the Pure acquisition are exercisable until the end of their full ten-year terms. Options are generally nontransferable except in the event of an employee’s death or pursuant to a court order.
Performance share awards outstanding at year-end have four-year terms and can be paid out in common stock and/or cash. The amount of the payout is based on a percentile ranking of the Company’s common stock total return relative to the total returns on the common stocks of a peer group of companies, subject to further downward adjustments at the discretion of the Management Development and Compensation Committee.
The directors’ units represent unfunded bookkeeping entries that are paid out in an equal number of shares of common stock at the end of the applicable deferral period. The unit holders do not have any voting rights until the common shares are issued. Dividend equivalents are credited to the unit holders as additional units.
Holders of restricted stock are entitled to vote the shares, and receive dividends, except that dividends for restricted stock granted under the Union Oil Restricted Stock Plan are accumulated and paid out when the shares vest. Restricted shares are not delivered until the end of the restricted period, which does not exceed ten years, unless distributed upon a qualified termination. Restricted stock is subject to forfeiture if the holder terminates employment during the restriction period for reasons other than for the convenience of the Company, death, disability or upon reaching normal retirement age.
In the event of a “change in control,” restricted stock will become vested, unvested options will become vested, performance shares will be paid out and directors’ units will be paid out if the director has elected accelerated payout upon a change in control.
A summary of the Company’s stock plans for the last three years is presented below:
Significant option groups outstanding at December 31, 2003 and related weighted average price and life information follows:
The estimated fair value at date of grant of options for common stock granted in 2003, 2002 and 2001, using the Black-Scholes option pricing model is as follows:
See Note 1 for pro-forma stock-based compensation expense if the Company had used the fair value accounting method recommended by SFAS No. 123.
NOTE 29 - FINANCIAL INSTRUMENTS AND COMMODITY HEDGING
The Company does not generally hold or issue financial instruments for trading purposes other than those that are hydrocarbon based. The counterparties to the Company’s financial instruments include regulated exchanges, international and domestic financial institutions and other industrial companies. All of the counterparties to the Company’s financial instruments must pass certain credit requirements deemed sufficient by management before trading physical commodities or financial instruments with the Company.
Interest rate contracts - The Company enters into interest rate swap contracts to manage its debt with the objective of minimizing the volatility and magnitude of the Company’s borrowing costs. The Company may also enter into interest rate option contracts to protect its interest rate positions, depending on market conditions. At December 31, 2003, the Company had approximately $22 million of after-tax deferred losses in accumulated other comprehensive income on the consolidated balance sheet related to cash flow hedges of interest rate exposures through September 2012. Of this amount, $3 million in after-tax losses are expected to be reclassified to the consolidated earnings statement during the next twelve months.
Foreign currency contracts - Various foreign exchange currency forward, option and swap contracts are entered into by the Company from time to time to manage its exposures to adverse impacts of foreign currency fluctuations on recognized obligations and anticipated transactions. At December 31, 2003, the Company had no deferred amounts in accumulated other comprehensive income on the consolidated balance sheet related to foreign currency contracts.
Commodity hedging activities - The Company uses hydrocarbon derivatives to mitigate its overall exposure to fluctuations in hydrocarbon commodity prices. The Company recognized $2 million of gains due to ineffectiveness for cash flow and fair value hedges in 2003. At December 31, 2003, the Company had approximately $10 million of after-tax deferred losses in accumulated other comprehensive income on the consolidated balance sheet related to cash flow hedges for future commodity sales for the period beginning January 2004 through December 2004. All of the after-tax losses are expected to be reclassified to the consolidated earnings statement during the next twelve months.
Fair values for debt and other long-term instruments - The estimated fair values of the Company’s long-term debt were $3.17 billion and $3.35 billion at year-end 2003 and 2002, respectively. Fair values were based on the discounted amounts of future cash outflows using the rates offered to the Company for debt with similar remaining maturities.
The estimated fair values of Unocal Capital Trust’s 6 ¼% convertible preferred securities were $532 million and $535 million at year-end 2003 and 2002, respectively. Fair values were based on the trading prices of the preferred securities on December 31, 2003 and 2002.
Concentrations of credit risks - Financial instruments that potentially subject the Company to concentrations of credit risks primarily consist of temporary cash investments and trade receivables. The Company places its temporary cash investments with high credit quality financial institutions and, by policy, limits the amount of credit exposure to any one financial institution. The concentration of trade receivable credit risk is generally limited due to the Company’s customers being spread across industries in several countries. The Company’s management has established certain credit requirements that its customers must meet before sales credit is extended. The Company monitors the financial condition of its customers to help ensure collections and to minimize losses.
During 2003, the Company took appropriate actions to help mitigate credit exposure to counterparties whose creditworthiness had deteriorated. In some cases, counterparty credit lines were reduced or rescinded. In other instances, the Company obtained credit assurances in the form of prepayments, letters of credit or guarantees to support the credit decision.
The majority of the Company’s trade receivables balance at December 31, 2003, was attributable to the sale of crude oil and natural gas produced by the Company or purchased by the Company for resale. The Company has receivable concentrations for its crude oil and natural gas sales and geothermal steam and related electricity sales in certain Asian countries that are subject to currency fluctuations and other factors affecting the region.
At December 31, 2003, the Company had a $182 million note receivable from URC (see note 12 for further details). The Company did not have any customers that accounted for 10 percent or more of its consolidated net trade receivable balance, excluding the URC note, at December 31, 2003. The Company’s highest account receivable balance with one customer was approximately $95 million from PTT Public Co., Ltd. This amount primarily represented payments due for sales of natural gas and crude oil from the Company’s Gulf of Thailand and offshore Myanmar operations.
At December 31, 2003, the Company’s business unit in Bangladesh had a gross receivable balance of approximately $26 million relating to invoices billed for natural gas and condensate sales to Petrobangla. Approximately $22 million of the outstanding balance represented past due amounts and accrued interest for invoices covering March 2003 through November 2003. The Company continues to work with Petrobangla and the government of Bangladesh regarding the collection of the outstanding receivables.
NOTE 30 - SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION
Unocal guarantees all the publicly held securities issued by its 100 percent-owned subsidiaries Unocal Capital Trust (see note 25 for further details) and Union Oil. Such guarantees are full and unconditional and no subsidiaries of Unocal or Union Oil guarantee these securities.
The following tables present condensed consolidating financial information for 2003, 2002 and 2001 for (a) Unocal (Parent), (b) the Trust, (c) Union Oil (Parent) and (d) on a combined basis, the subsidiaries of Union Oil (non-guarantor subsidiaries). Virtually all of the Company’s operations are conducted by Union Oil and its subsidiaries.
CONDENSED CONSOLIDATED EARNINGS STATEMENT
Year ended December 31, 2003
CONDENSED CONSOLIDATED EARNINGS STATEMENT
Year ended December 31, 2002
CONDENSED CONSOLIDATED EARNINGS STATEMENT
Year ended December 31, 2001
CONDENSED CONSOLIDATED BALANCE SHEET
At December 31, 2003
CONDENSED CONSOLIDATED BALANCE SHEET
At December 31, 2002
CONDENSED CONSOLIDATED CASH FLOWS
Year ended December 31, 2003
CONDENSED CONSOLIDATED CASH FLOWS
Year ended December 31, 2001
NOTE 31 - SEGMENT AND GEOGRAPHIC DATA
The Company’s reportable segments are as follows:
Exploration and Production Segment - This segment includes the Company’s North American and International oil and gas operations. North America includes the U.S. Lower 48, Alaska and Canada oil and gas operations. The Company’s International operations include activities outside of North America and are categorized under Far East and Other International. The Company’s International Far East operations include production activities in Thailand, Indonesia and Myanmar. The Company’s Other International operations include production in Bangladesh, the Netherlands, Azerbaijan, the Democratic Republic of Congo and Brazil. The Company is also involved in exploration and development activities in Asia, Australia, Brazil and West Africa. In 2003, $860 million, or approximately 13 percent, of the Company’s total external sales and operating revenues were attributable to the sale of natural gas and condensate, produced offshore Thailand and Myanmar, to PTT.
At the end of 2003, the Company had $131 million of goodwill recorded in its consolidated balance sheet. This amount included $92 million related to two acquisitions in North America made in 2002, which included $80 million in conjunction with the acquisition of the minority interests of Pure. The Company also recognized $30 million in goodwill related to one acquisition in North America in 2001. The Company periodically, and at a minimum annually, tests for impairment of goodwill. As of December 31, 2003, no such impairments had been recorded.
Trade Segment - The Trade segment externally markets most of the Company’s worldwide liquids production and North American natural gas production, excluding production of the Alaska business unit. It is also responsible for executing various derivative contracts on behalf of the Company’s Exploration and Production segment in order to manage the Company’s exposure to commodity price changes. The Trade segment also purchases liquids and natural gas from certain royalty owners, joint venture partners and unaffiliated oil and gas producing and trading companies for resale. In addition, the segment trades hydrocarbon derivative instruments, for which hedge accounting is not used, to exploit anticipated opportunities arising from commodity price fluctuations. The segment also purchases limited amounts of physical inventories for energy trading purposes when arbitrage opportunities arise.
Midstream Segment - The Midstream segment is comprised of the Pipelines business, which principally encompasses the Company’s worldwide equity interests in various petroleum pipeline companies and wholly-owned pipeline systems throughout the U.S., and the Company’s North America gas storage business.
Geothermal and Power Operations Segment - This segment produces geothermal steam for power generation, with operations in the Philippines and Indonesia. The segment’s current activities also include the operation of geothermal steam-fired power plants in Indonesia and equity interests in three gas-fired power plants in Thailand. The Company’s non-exploration and production business development activities, primarily power-related, are also included in this segment.
Corporate and Other - The Corporate and Other grouping includes general corporate overhead, miscellaneous operations (including real estate, carbon and minerals businesses) and other corporate unallocated costs (including environmental and litigation expenses). Net interest expense represents interest expense, net of interest income and capitalized interest.
The following tables present the Company’s financial data by business segment and geographic area of operations. Intersegment revenues, which are eliminated upon consolidation, in business segment data are primarily sales from the Exploration and Production segment to the Trade segment. Intersegment sales prices approximate market prices. The revenues presented in the geographic area disclosure table primarily represent sales of crude oil and natural gas produced within the countries or regions shown.
SEGMENT DATA
(a) Includes interest, dividends and miscellaneous income, and gain (loss) on sales of assets.
(b) Includes eliminations and consolidation adjustments.
SEGMENT DATA (continued)
(a) Includes interest, dividends and miscellaneous income, and gain (loss) on sales of assets.
(b) Includes eliminations and consolidation adjustments.
SEGMENT DATA (continued)
(a) Includes interest, dividends and miscellaneous income, and gain (loss) on sales of assets.
(b) Includes eliminations and consolidation adjustments.
GEOGRAPHIC INFORMATION
NOTE 32 - SUBSEQUENT EVENT
The Company’s wholly-owned Unocal North Sumatra Geothermal, Ltd. subsidiary sold its rights and interests in the Sarulla geothermal project on the island of Sumatra, Indonesia to the Indonesian state electricity company. The sales price was $60 million and the transaction closed on February 5, 2004. The Company will record an after-tax gain of approximately $20 million on the transaction.
QUARTERLY FINANCIAL DATA (Unaudited)
(a) Due to changes in the number of weighted average common shares outstanding each quarter, the earnings per share amounts by quarter may not be additive.
(b) Gross margin equals sales and operating revenues less crude oil, natural gas and product purchases, operating and administrative expenses, depreciation, depletion and amortization, impairments, dry hole costs, exploration expenses, and other operating taxes.
QUARTERLY FINANCIAL DATA (continued)
(a) Due to changes in the number of weighted average common shares outstanding each quarter, the earnings per share amounts by quarter may not be additive.
(b) Gross margin equals sales and operating revenues less crude oil, natural gas and product purchases, operating and administrative expenses, depreciation, depletion and amortization, impairments, dry hole costs, exploration expenses, and other operating taxes.
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
Results of Operations
Results of operations of oil and gas exploration and production activities are shown below. Sales revenues are shown net of purchases. Other revenues primarily include gains or losses on sales of oil and gas properties and miscellaneous rental income. Production costs include costs incurred to operate and maintain wells and related facilities, operating overhead and taxes other than income. Exploration expenses consist of geological and geophysical costs, leasehold rentals, amortization of exploratory leases and dry hole costs. Depreciation, depletion and amortization expense includes impairments and provisions of estimated future abandonment liabilities. Other operating expenses primarily include administrative and general expense. Income tax expense is based on the tax effects arising from the operations. Results of operations do not include general corporate overhead, interest costs, minority interests expense or the activities of the Trade business segment.
(a) Unocal’s proportional shares of investees accounted for by the equity method.
Results of Operations (continued)
(a) Unocal’s proportional shares of investees accounted for by the equity method.
Costs Incurred
Costs incurred in oil and gas property acquisition, exploration and development activities, both capitalized and charged to expense, are shown below. Data for the Company’s capitalized costs related to oil and gas exploration and production activities are presented in note 16.
(c) Represents Unocal's proportional shares of costs incurred by investees accounted for by the equity method.
(d) U.S. Lower 48 includes $73 million for the increased proved property basis resulting from the acquisition of the Pure minority interest shares.
(e) U.S. Lower 48 includes $48 million for the increased unproved property basis resulting from the acquisition of the Pure minority interest shares.
(f) U.S. Lower 48 includes $267 million cash for the acquisition by Pure of certain assets from International Paper Company.
(g) U.S. Lower 48 includes $173 million of cash, $87 million of net debt, $31 million of hedge liabilities and $11 million of other net liabilities assumed for the acquisition by Pure of the common stock of Hallwood Energy Corporation.
(h) Canada includes $93 million cash, $20 million of net debt and $4 million of other net liabilities for the acquisition of the common stock of Tethys Energy Inc.
Average Prices and Production Costs per Unit (Unaudited)
The average sales price is based on sales revenues and volumes attributable to net working interest production. Where intersegment sales occur, intersegment sales prices approximate market prices. The average production costs are stated on a BOE basis, which includes natural gas that is converted at a ratio of 6.0 Mcf to one barrel of oil equivalent, which represents the approximate energy content of the gas.
Oil and Gas Reserve Data (Unaudited)
Proved oil and gas reserves are estimated by the Company in accordance with the Securities and Exchange Commission’s definitions in Rule 4-10 of Regulation S-X. These definitions can be found on the SEC website at http://www.sec.gov/divisions/corpfin/forms/regsx.htm#gas.
The Company employs an extensive auditing process to assure quality reserve reporting. The reserves are calculated and reviewed by the individual business unit team of degreed engineering and geology professionals, and the results are then reviewed by a corporate team. For 2003, more than three-fourths of the Company’s reserves were reviewed by the corporate team, which is composed of individuals who have no management ties to the business units nor do they have any reserve volume goals. In addition, the auditing team includes one member from an independent third party engineering firm. The Company’s auditing team examines the existing reserve base on a rotating basis once every three years. All material changes in reserves each year are reviewed by the company’s management committee. As a matter of policy, the Company does not book reserves without management’s commitment to develop the project, which requires an established market for the resource.
Estimates of physical quantities of proved oil and gas reserves, determined by Company engineers, for the years 2003, 2002 and 2001 are presented on pages 138 and 139. These estimates do not include probable or possible reserves. Estimated oil and gas reserves are based on available reservoir data and are subject to future revision. Significant portions of the Company’s proved undeveloped reserves, principally in offshore areas, require the installation or completion of related infrastructure facilities such as platforms, pipelines, and the drilling of development wells. Proved reserve quantities exclude royalty and other interests owned by others, as well as volumes received by Company owned gas plants in lieu of processing fees. The Company reports all reserves held under PSCs in Indonesia, Myanmar, Bangladesh, Azerbaijan, Brazil and a concession in the Democratic Republic of Congo utilizing the “economic interest” method, which excludes host country shares. Estimated quantities for PSCs reported under the “economic interest” method are subject to fluctuations in the prices of oil and gas and recoverable operating expenses and capital costs. If costs remain stable, reserve quantities attributable to recovery of costs will change inversely to changes in commodity prices. This change would be partially offset by a change in the Company’s net equity share. The reserve quantities also include barrels of oil that the Company is contractually obligated to sell in Indonesia at prices substantially below market.
The Company reports natural gas reserves on a dry basis, with natural gas liquids presented with crude oil and condensate reserves. For informational purposes, natural gas liquids reserves are estimated to be 27 million, 30 million and 32 million barrels at December 31, 2003, 2002, and 2001, respectively. Of the aforementioned totals, 11 million, 12 million and 10 million barrels, for the respective periods, are located in the United States.
Estimated Proved Reserves of Crude Oil, Condensate and Natural Gas Liquids (a) (b)
Estimated Proved Reserves of Natural Gas (a) (b) (e)
Standardized Measure of Discounted Future Net Cash Flows (Unaudited)
The standardized measure of discounted future net cash flows from proved oil and gas reserves for the years 2003, 2002 and 2001 are presented on page 141. Revenues are based on estimated production of proved reserves from existing and planned facilities and on prices of oil and gas at year-end 2003. Development and production costs related to future production are based on year-end cost levels and assume continuation of existing economic conditions. Income tax expense is computed by applying the appropriate year-end statutory tax rates to pre-tax future cash flows less recovery of the tax basis of proved properties and reduced by applicable tax credits.
The following data on the standardized measure of discounted future net cash flows from existing proved oil and gas reserves are calculated in the manner mandated by the FASB and SEC and are based on many subjective judgments and assumptions. Estimates of physical quantities of oil and gas reserves, future rates of production and the timing of such production, future production and development costs and the timing of said expenditures are subject to extensive revisions and a high degree of variability as a result of operating, political and general business risks. Different, but equally valid, assumptions and judgments could lead to significantly different results.
As set forth in note (a) to the table on 141, the year-end prices required to be used in the calculations are highly volatile. Price changes have a significant impact on the calculated present values of proved oil and gas reserves. See “Changes in Standardized Measure of Discounted Future Net Cash Flows” table on page 142 for the aggregate changes and significant components of such changes for the last three calendar years.
Probable and possible reserves and the value of exploratory acreage that may be developed in the future have not been included in the calculation of the data presented on pages 141 and 142. Likewise, future realized prices are expected to vary significantly from the mandated year-end prices utilized in the determination of the revenues included in the calculations. While the Company has exercised due care in the preparation of the data, it does not warrant that this data represent the fair market value of the Company’s oil and gas properties or an estimate of the discounted present value of cash flows to be obtained from their development and production.
Standardized Measure of Discounted Future Net Cash Flows
(b) Includes dismantlement and abandonment costs. Future development costs include $3,911 million, $3,472 million and $3,373 million at December 31, 2003, 2002 and 2001, respectively required to promote proved undeveloped reserves.
(c) Represents proportional shares of investees accounted for under the equity method.
(d) Included in U.S. Lower 48 is the present value of Spirit Energy 76 Development, L. P., a consolidated subsidiary, in which there is a minority interest share representing approximately $69 million.
(e) Included in U.S. Lower 48 is the present value of Spirit Energy 76 Development, L. P., a consolidated subsidiary, in which there is a minority interest share representing approximately $95 million and the present value of Pure Resources, Inc., in which there is a minority interest share representing approximately $306 million.
Changes in Standardized Measure of Discounted Future Net Cash Flows (Unaudited)
(a) Reserves purchased were valued at $47 million, $106 million and $1,361 million in 2003, 2002 and 2001, respectively. Reserves sold were valued at $1,136 million, $69 million and $163 million for the same years, respectively.
OPERATING SUMMARY
(a) Reflects the sale of Gulf of Mexico shelf properties in U.S. Lower 48 in 2003, the acquisitions by Pure of International Paper Company assets and the Hallwood Energy Corporation acquisition in 2001, and the acquisition of Titan Exploration, Inc. by Pure Resources, Inc. in U.S. Lower 48 in 2000.
(b) Producible wells exclude suspended wells not expected to be producing within a year and wells awaiting abandonment.
(c) Excludes host countries' shares under certain production sharing contracts.
(d) Includes 100% of consolidated subsidiaries.
(e) Includes natural gas liquids previously included in natural gas quantities.
(f) Excludes natural gas liquids previously included in natural gas quantities.
OPERATING SUMMARY (continued)
(a) Includes the company's proportional shares of equity investees, 100% of consolidated subsidiaries.
(b) Natural gas is reported on a dry basis; production excludes gas consumed on lease.
(c) Includes reserves underlying a service fee arrangement in the Philippines.
(d) The 2002 increase reflects the signing of amended Joint Operations and Energy Sales Contracts covering operations in Indonesia, where the primary term of the contracts was extended to 2040 and the minimum annual take-or-pay was increased.
ITEM 9
ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE: None
ITEM 9A.
ITEM 9A. - CONTROLS AND PROCEDURES.
As of the end of the period covered by this report, the Company carried out an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rule 13a-15(e) of the Securities Exchange Act of 1934. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective in timely identifying material information potentially required to be included in the Company’s SEC filings.
There was no change in the Company’s internal controls over financial reporting that occurred during the fourth quarter of 2003 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.
Section 404 of the Sarbanes-Oxley Act of 2002 will require the Company to include an internal control report with its 2004 annual report on Form 10-K. The internal control report must assert (i) management’s responsibilities to establish and maintain adequate internal control over financial reporting and (ii) management’s assessment of the effectiveness of this internal control as of the end of the most recent fiscal year. The Company’s independent auditors will, in 2004, be required to audit, and report on, these assertions. In order to achieve compliance with Section 404 within the statutory period, management has formed a steering committee and adopted a detailed project work plan to assess the adequacy of the Company’s internal controls, remediate any control weaknesses that may be identified and validate through testing that controls are functioning as documented. The Company may make changes in its internal control processes from time to time.
PART III
The information required by Items 10 through 14 (except as otherwise indicated) is incorporated by reference to Unocal’s Proxy Statement for its 2004 Annual Meeting of Stockholders (the “2004 Proxy Statement”) (File No. 1-8483), as indicated below. The 2004 Proxy Statement is expected to be filed with the Securities and Exchange Commission on or about April 12, 2004.
ITEM 10
ITEM 10 - DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
See the information regarding Unocal’s directors and nominees for election as directors to appear in the 2004 Proxy Statement under the captions “Election of Directors” and “Board Committee Meetings and Functions.” Also, see the list of Unocal’s executive officers and related information under the caption “Executive Officers of the Registrant” in Part I of this report. See the information to appear in the 2004 Proxy Statement under the captions “Section 16(a) Beneficial Ownership Reporting Compliance” and “Other Information.”
In 2003, the Company adopted revisions to its code of conduct to address Section 406 of the Sarbanes-Oxley Act of 2002 relating to the code of ethics for the Chief Executive Officer and Chief Financial Officer and Corporate Comptroller. The Company’s code of conduct may be found on the internet at the following address: http://www.unocal.com/ucl_code_of_conduct/index.htm and the information is also available in print to any shareholder who requests it. Any amendments to, or waivers from the code of conduct that apply to the above named executive officers will also be posted to the website.
See the information on audit committee members and audit committee financial expert to appear in the 2004 Proxy Statement under the caption “Board Committee Meetings and Functions.” The Company’s corporate governance guidelines and board of director committee charters are available on the Company’s website and are available in print to any shareholder who requests them.
ITEM 11
ITEM 11 - EXECUTIVE COMPENSATION.
See the information regarding executive compensation to appear in the 2004 Proxy Statement under the captions “Summary Compensation Table,” “Option/SAR Grants in 2003,” “Aggregated Option/SAR Exercises in 2003 and December 31, 2003 Option/SAR Values,” “Long-Term Incentive Plans-Awards in 2003,” “Pension Plan Table,” “Employment Contracts and Termination of Employment and Change-in-Control Arrangements,” and the information regarding directors’ compensation to appear in the 2004 Proxy Statement under the caption “Directors’ Compensation.”
ITEM 12
ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
See the information regarding security ownership to appear in the 2004 Proxy Statement under the captions “Security Ownership of Certain Beneficial Owners” and “Security Ownership of Management.”
ITEM 13
ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
See the information regarding certain loans to executive officers to appear in the 2004 Proxy Statement under the captions “Indebtedness of Management” and “Certain Relationships and Related Transactions.”
ITEM 14
ITEM 14 - PRINCIPAL ACCOUNTANT FEES AND SERVICES.
See the information regarding the audit committee’s pre-approval policies and procedures and the disclosures of fees billed by the principal independent auditor to appear in the 2004 Proxy Statement under the caption “Independent Auditors Fees”.
PART IV
ITEM 15
ITEM 15 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a) Financial statements, financial statement schedules and exhibits filed as part of this annual report:
(1) Financial Statements: See the “Index to Consolidated Financial Statements and Financial Statement Schedule” under Item 8 of this report.
(2) Financial Statement Schedule: See the “Index to Consolidated Financial Statements and Financial Statement Schedule” under Item 8 of this report.
(3) Exhibits: The Exhibit Index on pages 150 through 153 of this report lists the exhibits that are filed as part of this report and identifies each management contract and compensatory plan or arrangement required to be filed.
(b) Reports filed on Form 8-K:
During the fourth quarter of 2003
(1) Current Report on Form 8-K, dated October 3, 2003, and filed October 6, 2003, for the purpose of reporting, under Item 5, the Company’s production forecast for the third and fourth quarters of 2003.
(2) Current Report on Form 8-K, dated October 29, 2003, and filed November 4, 2003, for the purpose of reporting under Item 5, the Company’s third quarter and nine months earnings results, other related information, the Company’s outlook for the remainder of 2003 and a discovery in the deepwater Gulf of Mexico.
During the first quarter of 2004 to the date hereof:
(1) Current Report on Form 8-K, dated January 13, 2004, and filed January 14, 2004, for the purpose of reporting, under Item 5, a discovery in the deepwater Gulf of Mexico.
(2) Current Report on Form 8-K, dated January 27, 2004, and filed February 6, 2004, for the purpose of reporting, under Item 5, the Company’s fourth quarter 2003 earnings and related information, the Company’s 2003 reserve replacement and finding development and acquisitions costs, the Company’s 2004 outlook.
(3) Current Report on Form 8-K, dated February 25, 2004, and filed March 4, 2004, for the purpose of reporting, under Item 5, a discovery in deepwater Indonesia and the sale of certain geothermal assets.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 11, 2004.
Signature
Title
/s/ CHARLES R. WILLIAMSON
Charles R. Williamson
Chairman of the Board,
Chief Executive Officer and President
/s/ JOHN W. CREIGHTON, JR.
John W. Creighton, Jr.
Vice Chairman of the Board of Directors
/s/ TERRY G. DALLAS
Terry G. Dallas
Executive Vice President and
Chief Financial Officer
/s/ JOE D. CECIL
Joe D. Cecil
Vice President and Comptroller
(Principal Accounting Officer)
/s/ JOHN W. AMERMAN
John W. Amerman
Director
/s/ CRAIG ARNOLD
Craig Arnold
Director
/s/ JAMES W. CROWNOVER
James W. Crownover
Director
/s/ FRANK C. HERRINGER
Frank C. Herringer
Director
/s/ RICHARD D. McCORMICK
Richard D. McCormick
Director
/s/ FERRELL P. McCLEAN
Ferrell P. McClean
Director
/s/ DONALD B. RICE
Donald B. Rice
Director
/s/ KEVIN W. SHARER
Kevin W. Sharer
Director
/s/ MARK A. SUWYN
Mark A. Suwyn
Director
/s/ MARINA v.N. WHITMAN
Marina v.N. Whitman
Director
UNOCAL CORPORATION AND CONSOLIDATED SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(Millions of dollars)
(a) Represents receivables written off, net of recoveries, reinstatement and losses sustained.
UNOCAL CORPORATION
EXHIBIT INDEX
The following Exhibits 10.2 through 10.40 are management contracts or compensatory plans, contracts or arrangements as required by Item 14 (c) of Form 10-K and Item 601 (b) (10) (iii) (A) of Regulation S-K.
* Previously filed.
** Filed herewith.
Copies of exhibits will be furnished upon request. Requests should be addressed to the Corporate Secretary.