CAPITAL: Washington, DC
MONETARY UNIT: Dollar
REFINING CAPACITY: 16,540,990 b/d
OIL PRODUCTION: 6,252,000 b/d
OIL RESERVES: 21 billion bbl
GAS RESERVES: 164 tcf
The American Petroleum Institute reported US oil production slid 5.6% to 5.902 million b/d in 1999, the largest annual decline in a decade.
Much of the decline came in Alaska, where production fell 10.7% from 1998. API explained that overall Alaskan production is on a decline curve, and there was some down time for equipment maintenance.
Alaskan production was 1.055 million b/d at the end of the year, vs. 4.93 million b/d for the Lower 48 states.
API noted that by early 2000 crude oil prices had recovered from the 1998-99 depression and returned to a level comparable to those in early 1997.
"The dramatic plunge in domestic oil exploration and development experienced during 1998 and early 1999 leveled off in the second half of the year and even increased late in 1999.
"Still, oil-related activity had not recovered to prior levels due to an apparent caution (among oil companies) in taking on new projects, the loss of wells that were permanently plugged, and concentration on the exploration and development of natural gas."
API said due to the oil price depression, upstream employment in late 1999 was 292,300 persons, down 60,000 jobs from 2 years earlier.
It said domestic deliveries of petroleum products grew 2.5% in 1999, the largest amount since 1996.
"Though domestic deliveries rose and production declined, 1999`s petroleum imports did not rise. Instead, they fell, with the additional supplies coming instead from a heavy draw on domestic inventories."
Total oil imports in December 1999 were 9.627 million b/d, down 6.2% from a year earlier. Imports` share of US deliveries fell to about 54% from 1998`s record high 56.6%.
API said US imports would have risen by 4% in 1999 if there had not been an unusually heavy drawdown of inventories.
API said the sources of US imports shifted in 1999. Middle East oil imports grew 10.9%, while imports from Venezuela, Canada, and Mexico together dropped 7.9%. Crude from Iraq more than doubled to 712,000 b/d.
API said refinery activity in 1999 did not increase for the first year since 1991.
The increase in demand was met instead by draws on product stocks. Utilization was 92.6%, down from 95.6% in 1998 and the lowest level since 1995. Meanwhile, operable capacity increased 3.1% to 16.3 million b/d.
Reserves drop
The US Energy Information Administration reported proved reserves of US crude oil fell 7% in 1998, the largest percentage decline in more than 50 years.
Crude reserves were 21.03 billion bbl, down 1.5 billion from the end of 1997.
An EIA study noted crude oil prices plunged in December 1998 to the lowest levels since in 1935, after adjusting for inflation.
It said falling crude prices led to a drop of almost 60% in rigs drilling for oil during 1998. This led to a decline in the number of new and producing oil wells, which was followed by the drop in oil reserves.
Only 24% of 1998 oil production was replaced by proved reserve additions.
The report said US dry gas reserves slipped 2% in 1998, ending 4 years of increases and offsetting two thirds of the gain from the prior 4 years. Natural gas reserve additions in 1998 replaced only 83% of gas production. US dry gas reserves at the end of 1998 were 168 tcf, down 3.2 tcf from the end of 1997.
GAS liquids reserves were 7.5 billion bbl, down 449 million bbl from the previous year.
EIA said crude oil reserve additions would have been even smaller in the absence of a few large, long-term development projects that were continued by their operators in the face of low oil prices, especially in California`s heavy-oil fields, where such projects helped that state`s reserves to increase.
"Despite a small drop in natural gas prices, gas well drilling increased," noted EIA. For both of the two leading US producing areas-Texas and the Gulf of Mexico federal offshore-proved reserves of gas were down in 1998.
The report said small increases in the deepwater gulf did not offset the persistent decline of proved gas reserves on the shallow gulf shelf.
Reserves and production of gas from unconventional sources like coalbed methane continued to grow in 1998. Coalbed methane reserves accounted for 7% of 1998`s proved gas reserves.
GAS resources
The Potential Gas Committee estimated that the available US natural gas resource base, including estimated proved reserves, had slipped to 1,205 tcf.
PGC estimated the yearend 1998 gas resource excluding reserves at 1,038 tcf. That total included 896 tcf attributable to traditional reservoirs and 141 tcf in coalbed methane reservoirs.
PGC said that, compared with yearend 1996, traditional resources decreased 2.7%, and the coalbed methane resource declined by 3.4%.
However, according to PGC estimates, future US gas supplies increased during the 1990s.
The total gas resource base was 1,172 tcf in 1990. More than 150 tcf was produced during 1990-98.
Changes in PGC`s estimates from 1996 to 1998 were primarily the result of the transfer of gas resources associated with existing fields to proved reserves in the North Central, Gulf Coast, Midcontinent, and Rocky Mountain areas.
Also, changes were made due to analysis of new seismic, drilling, and production data in each of those four areas.
Compared with 1996:
- The North Central region dropped 25.5% from 29.8 to 22.2 tcf.
- The Gulf Coast sector increased 0.2% from 264.9 to 265.5 tcf.
- The Midcontinent region fell 4.9% from 128.4 to 122.1 tcf.
- The Rocky Mountain sector declined 6.9% from 161.2 to 150 tcf.
- The Pacific region slipped 1.6% from 37.8 to 37.2 tcf.
- The Atlantic sector was unchanged at 103.9 tcf.
- Alaska remained unchanged at 193.8 tcf.
- Coalbed methane declined 3.4% from 146.3 to 141.4 tcf.
Spending plans
The US exploration and production industry was planning to increase capital spending in 2000.
Arthur Andersen, in its annual survey, said plans to increase outlays were due largely to the availability of attractive drilling prospects, expectations for a steady increase in US oil and gas demand, and continued strength in oil and gas prices.
It said half of the surveyed respondents indicated that they expected to see an increase in industry employment in 2000.
Overall, the survey said independent firms were more optimistic than the major integrated companies.
Arthur Andersen`s survey included 7 majors, 13 large independents, and 69 smaller independents. Of the 89 firms, 64% planned to increase US exploration spending in 2000. In the 1998 survey, only 29% contemplated increased US exploration spending for 1999.
Meanwhile, 67% of those surveyed planned to increase development spending within the US. In 1998, only 46% had said they would increase US development spending in 1999.
About 29% of those surveyed expect to increase spending for exploration outside the US in 2000, compared with the 16% that intended to do so in 1999. Meanwhile, 30% planned to increase non-US development spending in 2000 vs. 1999.
Arthur Andersen said, "Respondents continue to rate the US as the most attractive area for investment for the exploration and development of oil and gas, followed closely by Canada, West Africa, and the Middle East."
According to Arthur Andersen, about 55% of the respondents expected mergers and acquisitions to increase in 2000. And 87% thought significant gas reserves remain to be discovered in the US, compared with 89% in 1998.
Regarding oil, only 54% of respondents believed there were significant reserves to be found in the US vs. 59% in 1998.
Arthur Andersen said all companies agreed the deepwater Gulf of Mexico and Alaska had the greatest potential for oil and gas discoveries.
GASoline sulfur
The US Environmental Protection Agency (EPA) in 1999 issued a final rule that would require the industry to slash the sulfur content of gasoline from an average of 300 ppm (excluding California) to 30 ppm.
Beginning in 2004, refiners and importers could make or sell gasoline containing a range of sulfur levels, as long as all of their production was capped at 300 ppm and their corporate sulfur levels averaged 120 ppm during the calendar year.
In 2005, the refinery average would be set at 30 ppm, with a production cap of 300 ppm and a corporate average of 90 ppm. Both of the average standards could be met with the use of credits.
In 2006, refiners must meet a 30-ppm average sulfur level with a cap of 80 ppm.
In response to complaints from governors of western US states, EPA gave refiners in the Rocky Mountain region and Alaska an extra year to meet the standard. They would be allowed to meet a 150-ppm refinery average and a 300 ppm cap through 2006 but would have to meet the 30 ppm average and 80 ppm cap by 2007.
Small refiners (with less than 1,500 employees and less than 155,000 b/d of processing capacity company-wide) would face less-stringent, interim standards until 2008, when they must meet the final sulfur standards.
REFiners and importers of gasoline also could earn, bank, and trade sulfur credits for use in a later year or to sell to another refiner. EPA said that would lower costs for industry and clean air sooner.
The agency said the sulfur rule would cost less than 2¢/gal, but the oil industry put the cost at 5¢/gal.
EPA agreed with the auto industry`s argument that gasoline sulfur reductions were needed in conjunction with new tailpipe emission standards because sulfur fouls catalytic converters, which remove pollutants from auto exhaust. The refining industry had agreed with the need for reduced levels of sulfur in gasoline but argued that low-sulfur gasoline wasn`t necessary everywhere and wanted a longer phase-in period.
EPA said, when fully implemented in 2030, both the sulfur and auto emissions rule would reduce auto nitrogen oxides emissions (a key component of smog) by 74% and soot by 80%, equivalent to removing 164 million cars from the road.
The National Petrochemical and Refiners Association (NPRA) said the rule would require the refining industry "to make unprecedented investments in unproven technology to meet the rule`s timing requirements.
"It then assumes that those unproven technologies will work without a hitch to maintain the flow of gasoline to consumers without major upsets in supply or prices."
The American Petroleum Institute said, "We will do everything possible to meet EPA`s deadline and continue to serve our customers. To do so, however, it is essential that we receive full cooperation from state, local, and federal authorities in obtaining the necessary permits for refinery modifications."
Oxygenates debate
A National Research Council panel in 1999 concluded that the two principal types of oxygen additives used in reformulated gasolines (RFG) in the US contribute little to reducing ozone pollution.
The NRC study examined the differences between the additives ethanol and methyl tertiary butyl ether (MTBE) and concluded that RFG made with ethanol was less effective but that the overall effect of either oxygen additive on reducing ozone (a major component of smog) was very small.
William Chameides, study committee chairman, said, "Motor-vehicle emissions of chemicals that form ozone pollution have decreased in recent years. But that`s largely because of better emissions control equipment and components of reformulated gasolines-other than oxygen additives-that improve air quality.
"Although additives do reduce some pollutants from motor vehicle emissions, the oxygenates appear to have little impact on lowering ozone levels. Moreover, it is not possible to attribute a significant portion of past reductions in smog to the use of these gasoline additives."
Chameides was a professor of earth and atmospheric sciences at Georgia Institute of Technology, Atlanta.
The 1990 Clean Air Act Amendments required the use of RFG with oxygen additives in areas of the US that have substantial ozone pollution. RFG was designed to lower the emissions of vehicular pollutants.
Because of environmental questions about oxygenates, EPA had asked the National Research Council to study methods for certifying gasoline blends with oxygen additives.
The committee found that, compared with MTBE blends, ethanol blends result in more pollutants evaporating from vehicle gas tanks. Ethanol blends also increase the overall potential of vehicular emissions to form ozone.
It said that available data indicate that the potential for either additive to lower smog levels was small and would continue to decrease as other measures to reduce vehicle emissions take effect.
NRC said tougher air quality regulations and improvements to vehicles had substantially reduced emissions that help create near-ground ozone, and they could decrease further as more new technologies are incorporated.
MTBE in gasoline
An advisory panel in 1999 urged the EPA to restrict use of MTBE in gasoline "substantially" because the additive was showing up in drinking water supplies.
EPA Administrator Carol Browner said, "We must begin to significantly reduce the use of MTBE in gasoline as quickly as possible without sacrificing the gains we`ve made in achieving cleaner air."
The panel said it agreed "broadly, although not unanimously," that less MTBE should be used in the RFG program. The panel also urged the removal of the legal requirement that RFG contain 2 wt % oxygen for those metropolitan areas that fail to meet federal air quality standards for ozone.
It said, "Accomplishing any such major change in the gasoline supply without disruptions to fuel supply and price will require adequate lead time, up to 4 years if the use of MTBE is eliminated."
It said more study was needed on the health effects and groundwater characteristics of other ethers, such as ethyl tertiary butyl ether, before they were allowed to be placed in widespread use.
The panel urged EPA to accelerate enforcement of the replacement of underground gasoline tank systems and to have states prohibit fuel deliveries to nonupgraded tanks. The panel said EPA should work with state and local water suppliers to accelerate drinking water source protection in areas where MTBE in water had been a problem.
NPRA said it did not support an MTBE phaseout, but if that was required, refiners must be given adequate time to find acceptable substitutes, and the 2% oxygen requirement for gasoline must be repealed to give refiners flexibility.
The Oxygenated Fuels Association said, "We disagree with the panel`s view that reducing MTBE use is necessary. Reformulated gasoline with oxygenates like MTBE has been instrumental in significantly improving air quality for some 60 million Americans, and oxygenates like MTBE provide refiners with much-needed flexibility to produce cleaner-burning RFG."
Earlier in 1999, California Gov. Gray Davis had issued an executive order banning MTBE in gasoline sold in the state by Dec. 31, 2002.
Davis asked the California Environmental Protection Agency to implement the executive order, and asked the California Energy Commission and California Air Resources Board (CARB) devise a phaseout timetable.
Davis took the action after MTBE contaminated groundwater in certain areas of the state and after a University of California at Davis study concluded MTBE`s emissions effects were minimal and its health risks significant.
Smog, soot rule
The EPA in 1999 appealed to the US Supreme Court a federal appeals court decision that overturned the agency`s controversial smog and soot standards.
OIL industry groups, which had joined in the court appeal, praised the District of Columbia Court of Appeal`s decision. The American Trucking Association and the US Chamber of Commerce filed the suit.
In a 2-1 opinion, the justices said EPA overstepped its constitutional authority in promulgating the rule. The justices said EPA failed to show that the tougher rules were justified by health protection considerations and acted on legal assumptions that Congress had delegated powers to EPA that, under the Constitution, it cannot.
The opinion said EPA exceeded its authority because the standards for distinguishing between healthy and unhealthy levels of pollution were too vague.
"What EPA lacks is any determinate criterion for drawing lines. It has failed to state intelligibly how much (pollution) is too much," the court said. The opinion also said that, while the 1990 Clean Air Act Amendments required EPA to consider the health benefits of ozone as a shield to carcinogenic ultraviolet rays "in estimating the effects of ozone concentrations, EPA explicitly disregarded these alleged benefits."
The regulations were not scheduled to take effect in most areas until 2003, after increased monitoring of airborne pollutants.
Royalty rule
For the fourth time, the US Minerals Management Service revised its controversial proposal for a rule changing the way oil values are determined for calculating royalty on production from federal leases.
The action was aimed at resolving some of the major differences between MMS and industry. Since 1996, producers had disputed the service`s proposal for a royalty rule revamp, which would base most royalty values on spot prices for crude.
The industry agreed that the old valuation system was obsolete but disagreed with the complex system MMS proposed, which in many cases moved the valuation point downstream of the lease. The industry recommended that MMS take the federal royalty in kind.
MMS planned to issue a final rule early in 2000, when a congressional moratorium expired.
The agency said it would repropose a separate rule for valuing oil production from Indian leases. It planned to issue a final rule by April 2000.
California leases
US Interior Sec. Bruce Babbitt ordered that 36 leases off California continue under suspension, in deference to requests by California`s Gov. Davis and the California Coastal Commission (CCC).
The action fell short of demands by the state, which sued Interior alleging the federal agency failed to allow the state to review lease renewals and "suspensions" (extensions).
In issuing the suspension, Babbitt ordered an environmental analysis of the impact of drilling off the central California coast and said that the leases would continue to be suspended until that review was finished and that California state agencies could comment on it.
The MMS estimated the original 40 leases held 1 billion bbl of oil and 500 bcf of natural gas. They were leased during 1968-84 for $1.25 billion.
In 1999, California legislators asked the Clinton administration to terminate the 40 leases along San Luis Obispo, Santa Barbara, and Ventura counties.
After CCC threatened a lawsuit against Interior for more review authority, Babbitt canceled four of the 40 leases, citing "regulatory deficiencies."
OIL company representatives said the "deficiencies" were a disagreement over whether there was enough oil under those leases. Aera Energy Inc., Bakersfield, Calif., operated three of the canceled leases, and Samedan Oil Corp. operated the fourth.
Interior asked the holders of the 36 remaining leases to explain how their plans would address impacts on sea otters and other marine life, the Monterey Bay National Marine Sanctuary (established in 1995 after the tracts were leased), new air and water quality standards, and changes in drilling technology.
NPR-A sale
ARCO Alaska Inc. and Anadarko Petroleum Corp., bidding as partners, dominated a May 1999 National Petroleum Reserve-Alaska onshore lease sale.
Six companies participated in the sale, offering apparent high bids of $104,635,728 for 134 North Slope tracts-all but a few in the northeastern corner of NPR-A.
The ARCO-Anadarko partnership picked up 92 of the blocks. The US Bureau of Land Management said the sale attracted 174 bids totaling $124,951,166.
Companies concentrated their bidding in the coastal region between the Colville River and Teshekpuk Lake, in the general area of the 1994 Alpine field discovery. Another concentration of blocks was sold between Teshekpuk Lake and the Ikpikpuk River.
ARCO Alaska (78%) and Anadarko (22%) offered the highest bid in the sale, $3,655,100 for tract H-51. BP Exploration (Alaska) Inc. (72%) and Phillips Petroleum Co. (28%) bid $271,100 for the same block.
The sale, the first in NPR-A since 1984, offered 425 tracts on 3.9 million acres. The federal government shared 50% of the sale revenues with the state.
ARCO and Anadarko were owners of Alpine field, across the Colville River from some of the NPR-A sale tracts. Like their bidding partnership, they were 78% and 22% owners of Alpine.
The Interior Department placed extensive environmental stipulations on many of the blocks offered.
Coalbed methane
In a major decision for gas companies, the US Supreme Court ruled that coalbed methane and coal reserves could be separately owned.
The high court ruled 7-1 that private landowners, not the Southern Ute Tribe, own the coalbed methane reserves in the vicinity of the reservation in southern Colorado.
The tribe had estimated it might be owed $1 billion in royalties and interest.
The case, Amoco Production Co. vs. Southern Ute Indian Tribe, was expected to affect other coalbed methane production in the West.
The Independent Petroleum Association of Mountain States said more than 20 million acres of western lands could be affected.
In the Coal Lands Acts of 1909 and 1910, Congress claimed the rights to coal under the reservation and later awarded them to the tribe. Nothing was said about the methane, then considered both hazardous and worthless.
OIL companies began producing coalbed methane from tribal and private lands in the reservation in the early 1980s. In 1991 the tribe sued, claiming it owned the gas on what were then private lands because it owned the coal.
The tribe lost in district court but won before the 10th Circuit Court of Appeals. In the process, the Interior Department reversed itself and opposed the oil firms in the suit.
Justice Anthony Kennedy, writing for the Supreme Court, said Congress didn`t consider the gas part of the coal 80 years earlier when it passed two laws letting homesteaders claim the land while keeping the coal for the federal government.
He said, "The common conception of coal at the time Congress passed the 1909 and 1910 acts was the solid rock substance that was the country`s primary energy source. The question is not whether, given what scientists know today, it makes sense to regard (coalbed methane) gas as a constituent of coal, but whether Congress so regarded it in 1909 and 1910."
SPR refill
The US Department of Energy shifted 23 million bbl of federal royalty oil in 1999 from the central Gulf of Mexico for storage in the Strategic Petroleum Reserve.
Energy Sec. Bill Richardson announced the SPR replenishment as part of initiatives to help small oil producers hurt by low crude prices but said the action was not intended to raise the price of oil in the US.
The fill, plus 5 million bbl later, would equal what the government sold to help reduce its budget deficit in fiscal 1996 and 1997, at an average price of $19.50/bbl.
DOE and the Interior Department agreed for the latter to take federal offshore royalty oil in kind rather than in cash. That would enable DOE to refill the SPR without a congressional appropriation or offsetting revenues.
The crude went to the Big Hill, Tex., SPR site. DOE traded royalty oil not meeting SPR specifications for other crudes.
The four SPR sites in Louisiana and Texas had capacity for 680 million bbl. Before the refill program they held 561 million bbl, acquired for an average $27/bbl.
DOE also offered to let US oil companies store crude in the SPR, but no companies accepted.
It offered to allow producers to store up to 70 million bbl of oil for at least 1 year. DOE would have charged storage fees in the form of oil.
Dumping case
The US Department of Commerce in 1999 rejected a landmark trade case that accused Saudi Arabia, Venezuela, Mexico, and Iraq of dumping crude oil at unfair prices in the US.
Save Domestic Oil Inc. (SDO), a group of independent oil producers, brought the action in June 1999, claiming that low-priced imports had forced many independents out of business. But many other oil companies, ranging from large to small, opposed the case and claimed that SDO represented only a small slice of the domestic industry. Venezuela and Mexico also lodged stiff protests.
After an inquiry, the Commerce Department`s International Trade Administration ruled the petitioners failed to meet the legal threshold of adequate industry support, and thus it would not proceed to examine the merits of the case.
SDO appealed ITA`s decision to the federal Court of International Trade.
The dumping case was believed to have been the first to involve a widely traded commodity like oil.
SDO alleged the four nations had sold government-subsidized oil at unfairly low prices in the US market from 1998 into early 1999. The four nations provided more than half of US oil imports during the period. Prices fell as low as $10/bbl during the period.
The SDO case had to clear two major hurdles before Commerce could investigate the allegations. The group filing the petition had to represent producers with 25% of US oil production, and the petition had to be supported by at least 50% of the producers that expressed an opinion on the matter to the Commerce Department.
Commerce surveyed 810 producers to gauge whether they supported or opposed the case. SDO claimed it had the support of 1,500 individual producers since its petition was supported by industry groups with that total membership.
And SDO said Commerce should ignore the opposition of large oil companies and refiners who bought production from the four nations or had other business relationships with them.
The majors argued that they, too, were domestic producers and therefore their opposition should be counted. Commerce did count them and calculated industry opposition was as high as 68%.
The American Petroleum Institute, which strongly opposed the SDO case, said, "There is no question that low world oil prices have seriously harmed US producers, their workers, and related businesses. Many thousands of people have lost their jobs, and many firms have shut down.
"But these low prices were set by the forces of supply and demand in international markets, not by alleged unfair pricing by a handful of oil-producing countries."
Other actions
Meanwhile, the US Commerce Department was conducting an inquiry, under Sect. 232 of the Trade Expansion Act, to determine if rising imports of crude and products threatened national security.
There was little doubt about the ultimate conclusion. Similar investigations in 1975, 1979, 1988, and 1995 found rising imports were a national security threat, and US dependence on foreign crude had grown since then.
OIL groups were concerned about what the Clinton administration would recommend as a result of the study.
The law gives the President power to "adjust imports" if they were a threat. Administration officials said an oil import fee would not be recommended.
A law was enacted providing federal loan guarantees for domestic oil and gas firms.
Under the program, independent petroleum producers and small business service companies would be able to borrow up to $10 million each until total loans reached $500 million.
The bill provided a government-backed repayment guarantee for 85% of each loan, making it possible for commercial lenders to offer more lenient terms than they would otherwise. The Commerce Department was administering the oil loan program.
GAS-to-liquids
Atlantic Richfield Corp. and Syntroleum Corp., Tulsa, started a 70 b/d pilot gas-to-liquids (GTL) unit at ARCO`s Cherry Point refinery in Bellingham, Wash.
The technology promised to make production possible from many remote gas fields. If natural gas can be converted to a liquid economically, then it could be shipped via tanker-avoiding the high cost of pipeline construction.
The Bellingham unit achieved initial operating targets, and an evaluation program was proceeding, said ARCO.
The pilot plant was testing reactor designs developed jointly by ARCO and Syntroleum and an improved high-performance Fischer-Tropsch catalyst developed by Syntroleum.
Syntroleum`s GTL technology included two proprietary processes: one for conversion of natural gas to synthesis gas (a mixture of hydrogen and carbon monoxide), and one for conversion of synthesis gas to synthetic fuels or petrochemicals.
The first reaction step was achieved in an autothermal reformer and the second in a Fischer-Tropsch synthesis reactor.
ARCO Technology and Operations Services led the Cherry Point project.
"The successful integration of the new catalyst system and the advanced reactor design represents a major step forward in assessing this important technology," said Jeff Bigger, ARCO`s GTL technology manager.
"We will build upon the knowledge gained in this plant to refine our design concepts for large-scale plants. Our ultimate goal is to deploy an economically attractive design for commercializing stranded natural gas resources."
Syntroleum Pres. and Chief Operating Officer Mark Agee said the project "expands our base of reactor designs and catalyst systems, and we expect it will further lower capital costs in large-scale applications."
Mergers
The US oil industry saw several major mergers in 1999.
The US Federal Trade Commission allowed Exxon Corp. to acquire Mobil Corp. for $81 billion but required the companies to sell many assets.
FTC gave Exxon Mobil Corp. 9 months to divest 2,431 US gasoline stations. The company had to sell 1,740 service stations in the Northeast and Mid-Atlantic states, all 360 Exxon stations in California stations within 9 months, all 319 Mobil stations in Texas, and 12 stations they both owned in Guam.
The merged firm had to sell Exxon`s 129,500 b/d Benicia, Calif., refinery and guarantee to supply the new owner up to 100,000 b/d of Alaska North Slope crude oil for 10 years.
Alaska Atty. Gen. Bruce Botelho said he would require Exxon Mobil to divest Mobil`s 3% share of the Trans-Alaska Pipeline System. Exxon owned 21% of the pipeline.
The merged firm also had to sell Exxon`s 48.8% stake in the Plantation pipeline or Mobil`s 11.49% interest in the Colonial pipeline.
Meanwhile, FTC raised objections to BP Amoco PLC`s planned $38 billion acquisition of Atlantic Richfield Corp.
FTC was concerned BP Amoco-ARCO`s dominance in Alaskan crude production could enable it to control California gasoline prices.
In negotiations with Alaska, BP Amoco agreed to divest many of its or ARCO`s assets in that state to maintain oil industry competition, but opponents said the combined firm still would dominate North Slope operations.
The agreement would limit BP Amoco`s North Slope ownership to 55%.
BP Amoco agreed to sell producing assets amounting to 175,000 bo/d of output, together with associated infrastructure, 620,000 acres of Alaskan exploration leases, and a 13% stake in the Trans-Alaska Pipeline System.
The deal would enable BP Amoco to keep just over half of ARCO`s current production in Alaska, roughly 175,000 bo/d.
The company would also retain more than 1 million acres of exploration territory on the North Slope, including 430,000 acres in the National Petroleum Reserve-Alaska.
BP Amoco expected to divest ARCO`s operatorships in Kuparuk River and Alpine fields, with the 175,000 b/d reduction in oil production coming primarily from Kuparuk.
The company also agreed to make up to 1.2 bcfd of North Slope gas available to commercial projects at competitive prices. The deal included commitments to pay for environmental cleanups, to support local producers, and to hire local staff, as well as to donate $8 million/year to social projects.
Other mergers
Dow Chemical Co., Midland, Mich., and Union Carbide Corp., Danbury, Conn., vaulted themselves into the number two position among chemicals producers by announcing a merger.
The $11.6 billion transaction envisioned a Dow Chemical with $24 billion in revenues, a market capitalization of $35 billion, and assets of more than $30 billion. Under the deal, Union Carbide shareholders would get about 25% of Dow`s stock.
Dow and Union Carbide had similar product portfolios and expected to achieve significant synergies as a result of their union.
El Paso Energy Corp., Houston, and Sonat Inc., Birmingham, Ala., agreed to merge and create a US natural gas powerhouse with a total enterprise value of more than $14 billion.
The proposed deal was valued at $6 billion, including the assumption of $2 billion in Sonat debt. It involved a 1-for-1 stock swap.
The merged firm, called El Paso Energy, had a broad range of assets in interstate and intrastate gas transmission, gas gathering and processing, energy marketing, and power generation.
El Paso contributed its five business units-Tennessee Gas Pipeline, El Paso Natural Gas, El Paso Field Services Co., El Paso Energy Marketing Co., and El Paso Energy International. El Paso also owned an interest in Leviathan Gas Pipeline Partners LP.
Sonat contributed its Southern Natural Gas Co., Sonat Exploration Co., Sonat Marketing Co. LP, and Sonat Power Marketing units.
Their combined interstate transmission systems totaled 40,600 miles of pipeline, ahead of the second largest transporter, Enron Corp. with 32,000 miles.
The merged company became the largest US gas transporter at 12.4 bcfd, followed by Williams at 9.2 bcfd. And it would be the third largest physical marketer of natural gas, with 6.4 bcfd.
Fort Worth`s Snyder Oil Corp. and Houston`s Santa Fe Energy Resources planned to merge into Santa Fe Snyder Corp. with a market capitalization of more than $1 billion.
Santa Fe`s previous shareholders would own 60% of the new company and Snyder`s 40%.
