OGJ Newsletter

U.S. Industry Scoreboard 2/5 (73381 bytes)

Oil prices have seesawed about $1/bbl since Iraq and the U.N. late last month agreed to meet in New York Feb. 6 to discuss limited Iraqi oil sales to pay for food and medical supplies.

Although it appears weaker market fundamentals are as much to blame for falling prices as the threat of Iraq's return to oil exports, media coverage of the Iraq issue is expected to make traders more nervous than usual. Brent crude for March delivery closed at $16.52/bbl Jan. 31, compared with $16.98 Jan. 24 and $16.03/bbl Jan. 29.

London's UBS Securities analyst Geoff Pyne notes that while word of the Iraq/U.N. meeting shivered markets, oil prices have fallen $2.50/bbl since Jan. 1.

"In late December, inventories were short and demand was high, and it was touch and go whether crude oil requirements would be met. Now inventories are not so high, spring is approaching, and demand has eased.

"If Iraq had remained out of the equation, prices would have gone down, anyway. Iraq has merely lubricated the path downwards."

Pyne said traders fall into two camps over the talks, believers and skeptics. He confessed himself a skeptic, saying that besides doubts over the true motives and intentions of Saddam Hussein, the U.N.'s internal mechanisms could militate against an agreement. Pyne thinks the U.N. bureaucracy will want its bills paid for the weapons census in Iraq as part of the deal, while the Security Council is expected to insist on Saddam meeting resolutions on weapons and future monitoring of military operations.

"I don't think an agreement will happen," said Pyne, "but in the meantime there is the potential for lots of news flow about Iraqi oil and lots of possibilities for spooking oil markets." Even if the skeptics are right and Iraq fails to agree even on limited oil sales, Pyne said there still is little scope for oil prices to rebound, given market fundamentals.

Meantime, OPEC reacted to news of the Iraq/U.N. meeting by saying, "An extraordinary meeting of the conference will be convened in order to take the appropriate measures, at the time when an agreement is reached between the U.N. and Iraq on the resumption of Iraqi oil exports into world markets."

Gas market liberalization in the U.K. is traveling a bumpy road.

U.K. Department of Trade & Industry (DTI) is finalizing legislation for opening Britain's residential gas market to competition and expects a pilot scheme to start up Apr. 1 as planned. As of Apr. 1, 500,000 residences in Southwest England will be able to choose their gas supplier for the first time. This pilot scheme is expected to lead to opening the market fully in 1998.

There are two final regulatory drafts needed for companies wishing to enter the deregulated market. On Jan. 25, DTI published a final draft of gas transporters' licenses that sets out requirements for gas suppliers to use BG's grid to supply their customers. DTI also published a final draft of rules outlining data needed for license applicants. All regulations and gas supply monitoring systems required to operate the pilot scheme are expected to be operational Mar. 1, giving new suppliers only 1 month to prepare for live operation.

Meanwhile, DTI also has rejected calls by British Gas for help with $60 billion in long term take or pay supply contracts that were compromised by collapse of spot gas prices. BG had sought a levy to be charged new suppliers to help it pay for gas bought under agreements made long before liberalization became an issue. BG is suing its main suppliers, Shell U.K. and Esso U.K., in a bid to have the contracts voided (OGJ, Dec. 11, 1995, p. 30).

U.K. electricity customers may face blackouts as gas demand there hits a record high. British Gas Transco logged a record 24 hr gas dispatch of 378.7 million cu m Jan. 25. This beat a previous peak of 369 million cu m just before Jan. 1 and was 6.2% more than the U.K. record prior to this winter.

As residential users burned more gas, BG cut cheap supplies to industrial customers on interruptible supply contracts, including electricity generators that lost fuel for gas fired power stations. On Jan. 29, electricity generators, which usually have gas supplied on interruptible contracts and often use oil fired power stations only as backup, threatened power cuts.

In the end the power companies avoided supply blackouts, but there remains widespread concern over generators' ability to cope with demand surges, as they switch increasingly from oil to gas.

London's International Petroleum Exchange will begin limited trading of natural gas futures contracts in mid-April, shortly after delivery of first supplies under the liberalized market begins. IPE wanted trading systems in place Mar. 1 but cited delays in introducing a network code to govern third party access to BG pipelines. Monthly contracts for delivery of gas to Bacton terminal will be traded at first, with contracts for the U.K.'s five other delivery points to be added if early trading is successful. IPE let a $300,000 contract to London's CMG U.K. to develop and launch its forward trade gas contracts.

Rep. William Thornberry (R-Tex.) has introduced legislation to lower the U.S. tax rate on LNG used as a transportation fuel. In 1993's budget reconciliation act, Congress set a 48.5/Mcf excise tax on CNG, about 5.9/gal gasoline equivalent. LNG advocates said LNG was not mentioned in the law because it was not used as a fuel-except in municipal bus fleets-at the time.

That prompted IRS in 1995 to list LNG as "other liquid fuel" subject to a 31.5/gal tax, or 25.6/gal higher than CNG. LNG advocates contend LNG is no different from CNG when burned in an engine, and advances in technology and distribution systems make LNG use viable in medium and heavy duty vehicles, but the higher tax rate makes it uneconomic (see Journally Speaking, p. 23).

Selective refinery strikes in the U.S. looked likely at presstime last week.

The Oil, Chemical, & Atomic Workers Union (OCAW) was planning selective strikes after its national policy committee was to meet in Denver through Feb. 2. This follows rejection of a third pattern contract offer by industry, led by Amoco (OGJ, Jan. 29, p. 33). Labor-management talks marked no progress as of Jan. 31, when current contracts were to expire. OCAW offered Jan. 31 to let certain refineries extend contracts on a rolling, 24 hr basis while talks continue, warning this did not mean a settlement was imminent.

Refinery sources see the contract extensions and the fact no walkouts were planned for Feb. 1 as good signs a settlement is close.

"If negotiations were really deadlocked, you'd see some protest planned the day after contracts expired," a refinery official said. Another encouraging sign was that only selective strikes were being considered, sources said. That suggests little disruption to the U.S. refining system. OCAW suggests potential trouble spots are refineries owned by Mobil at Chalmette, La., and Beaumont, Tex., Tosco at Martinez, Calif., Crown Central at Pasadena, Tex., BP/Tosco at Marcus Hook, Pa., Total at Alma, Mich., and Unocal/Pdvsa at Lemont, Ill.

Despite federal and state agency support and a judge's affirmation, Exxon still can't get permission to tanker its Offshore California crude from the Santa Barbara County Board of Supervisors, although the tankering occurs far from Santa Barbara.

Last year, Exxon transported some crude produced off Santa Barbara and moved then via pipeline to San Francisco for tankering to Los Angeles. The county claims Exxon violated an early agreement not to tanker at all, but Exxon insists the county's authority ends at its borders. The county wants Exxon to apply for a tanker permit that proves a lack of alternative pipeline capacity to Los Angeles, although MMS and a federal judge sided with Exxon, and the California Coastal Commission wouldn't support the county's appeal of the MMS decision.

Exxon now must either return to the judge for a ruling blocking the county from interfering with its circuitous tankering or comply with the county's ruling.

More U.S. majors are bumping up capital spending for 1996 (see related story, p. 39). Conoco plans about $2.25 billion for capital and exploration spending this year, up 20% from 1995 outlays.

That breaks out as $1.6 billion non-U.S. vs. $660 million U.S. and by segment $1.45 billion for E&P and gas processing, $785 million for refining/marketing and transportation, and $25 million for power generation.

Large Canadian oil and gas companies continue to report strong 1995 profits. Imperial cites higher oil prices that helped it log a 1995 profit of $514 million (Canadian), up 43% from 1994. Shell Canada reports a record 1995 profit of $523 million-vs. $320 million in 1994-that stemmed from a $95 million gain from sale of its polypropylene business and positive results from higher oil and chemical prices and reduced costs that were offset slightly by weak gas prices.

TransCanada PipeLines cites record earnings of $397.5 million in 1995, up 11% from 1994. TransCanada also reported its first income from a foreign project, $4.7 million in equity income from its 44% interest in Colombia's Cusiana oil pipeline. About 80% of TransCanada's earnings come from its Canada-U.S. gas pipeline. Also reporting record income in 1995 was NOVA, with $702 million, up 54% from 1994. NOVA cites strong earnings at the first of the year that weakened by the fourth quarter, tracking a slide in petrochemical prices.