CAPITAL: Washington, D.C.
MONETARY UNIT: Dollar
REFINING CAPACITY: 16.4 million b/cd
OIL PRODUCTION: 6.37 million b/d
OIL RESERVES: 22.5 Billion bbl
GAS RESERVES: 167 tcf
The benefits of past exploration and development and sharply improved efficiency made a strong appearance in 1998, even as upstream activity sagged in response to slumping prices for oil and natural gas.
The U.S. Energy Information Administration reported in September 1998 that the country`s reserves of crude oil had increased in 1997 for the first time in a decade. Reserves of dry natural gas in 1997 increased for the fourth straight year, while reserves of natural gas liquids increased for the third straight year.
The reserves numbers, as of Dec. 31, 1997, and changes from the previous year: Crude oil 22.546 billion bbl, up 2.4%; dry gas 167.223 tcf, up 0.4%; and NGL 7.973 billion bbl, up 1.9%.
More than half the oil increase came from revisions to reserves in some of California`s old heavy-oil fields. Discoveries on the Outer Continental Shelf also boosted the reserves totals for oil and gas.
EIA noted that total discoveries per exploratory oil well were 50% higher in 1997 than they were in 1996 and more than six times the rates of the price and drilling-boom years of the early 1980s (Fig. 1).
Crude oil
For crude oil, total discoveries amounted to 1.233 billion bbl in 1997, compared with 927 million bbl in 1996. The discovery total was about double the average for the preceding 10 years.
Federal leases in the Gulf of Mexico yielded more than 50% of total discoveries of crude oil, Texas 15%, and Alaska 11%. Much of the gulf increases were in deep water-water deeper than 200 m.
New-field discoveries added 637 million bbl to crude reserves in 1997, compared with 243 million bbl in 1996. The figure was more than five times the average for the previous decade.
The gulf OCS accounted for 79% of new-field discoveries, Alaska 18%, and the rest of the country less than 3%. EIA noted that "well over half" of gulf oil reserves lie under deep water.
New-reservoir discoveries in old fields totaled 119 million bbl in 1997 vs. 141 million bbl the year earlier. Field extensions added 477 million bbl to crude oil reserves vs. 543 million bbl in 1996.
Revisions and adjustments came to a net 1.434 billion bbl in 1997, compared with 912 million bbl in 1996. Texas and California accounted for more than half the total.
Alaska`s oil reserves fell 2% to 5.161 billion bbl in 1997, while Lower 48 reserves gained 4% to 17.385 billion bbl.
Among the main producing states, reserves fell fractionally in Texas to 5.687 billion bbl, rose 9% in California to 3.75 billion bbl, fell 1% in New Mexico to 735 million bbl, rose 9% in Louisiana to 714 million bbl, rose 4% in Wyoming to 627 million bbl, and fell 4% in Oklahoma to 605 million bbl.
Reserves in the federal offshore jumped 13% to 3.477 billion bbl. Of that total, the OCS off Louisiana accounted for 2.587 billion bbl, off Texas 362 million bbl, and off California 528 million bbl.
EIA said indicated reserves of crude oil-volumes that may become economically recoverable from known reservoirs with application of improved recovery techniques involving current technology-increased to 3.207 billion bbl in 1997. Large indicated reserves occurred in northern Alaska, California, Texas, and Louisiana.
GAS reserves
For natural gas, reserves gains by revision and adjustment in Alaska more than offset a slight decline in the Lower 48.
Reserves increases were largest in the federal offshore and Texas.
Total dry gas discoveries, at 15.648 tcf, were up 27% from 1996 and the highest they had been in a decade. More than 60% of the total came in Texas and the Gulf of Mexico OCS.
New-field discoveries totaled 2.681 tcf in 1997 vs. 1.451 tcf in 1996. They were twice the average of the preceding 10 years.
New-reservoir discoveries in old fields added 2.382 tcf in 1997, compared with 3.11 tcf in 1996.
Field extensions came to 10.585 tcf, compared with 7.757 tcf in 1996.
EIA said coalbed methane reserves grew faster than conventional gas reserves and accounted for nearly 7% of the 1997 total.
Total discoveries of gas per exploratory gas well increased in 1997 to a rate more than four times those of the early 1980s.
Alaskan dry gas reserves increased 14% to 10.562 tcf. Reserves in the Lower 48 declined fractionally to 156.661 tcf.
GAS reserves fell 1% in Texas to 37.761 tcf, fell 6% in New Mexico to 15.514 tcf, jumped 10% in Wyoming to 13.562 tcf, rose 3% in Oklahoma to 13.439 tcf, and rose 1% in Louisiana to 9.673 tcf.
Dry gas reserves on OCS leases fell 2% to 28.466 tcf. The Louisiana OCS accounted for 21.934 tcf, the Texas OCS 5.988 tcf, and the California OCS 544 bcf.
NGL reserves
In Alaska, reserves of NGL rose 87% in 1997 to 631 million bbl, all due to revisions and adjustments. Lower 48 reserves of NGL fell 2% to 7.342 billion bbl.
Texas reserves of NGL rose 3% to 2.687 billion bbl.
NGL reserves fell 18% in New Mexico to 869 million bbl, rose 5% in Utah and Wyoming combined to 761 million bbl, and remained steady in Oklahoma at 685 million bbl.
In the federal offshore, NGL reserves rose 19% to 920 million bbl, of which 785 million bbl was off Louisiana, 121 million bbl off Texas, and 14 million bbl off California.
Activity slumps
The reserves upturn was destined not to last, however. In 1998, drilling activity plummeted as the prices of crude oil and-to a lesser degree-natural gas nosedived.
The year`s average wellhead price of crude oil fell to an estimated $10.80/bbl in 1998 from $17.24/bbl in 1997 and $18.46/bbl in 1996. The price hadn`t been that low since the $9/bbl average of 1978.
The average U.S. wellhead price of natural gas fell to $1.75/Mcf in 1998 from $2.23/Mcf in 1997 and $2.17/Mcf in 1996.
In response, drilling slumped in the U.S. Well completions fell to an estimated 23,900 in 1998 from 29,139 in 1997. The total still was higher than those of 1994 and 1995, however.
The weekly Baker-Hughes count of active rotary rigs averaged 830 for 1998, but the trend was sharply down. In the last week of the year the count was 634. By the end of January it had fallen below 600 and was setting modern record lows week by week.
The rig market
While activity declined, availability of drilling rigs rose in 1998, according to the annual rig census by Reed Tool Co. Reed reported results of its census at the annual meeting of the International Association of Drilling Contractors.
The company counted 1,705 rigs available in the U.S., up 40 from the 1997 level and the second straight annual gain following 14 years of decline.
But activity fell by 142 units to 1,305 active rigs. The Reed census counts as active any rig drilling during a specified 45 day period in summer.
Fleet utilization, the share of available rigs active during the census period, fell to 76.5% in 1995 from 87% in 1997, returning to the utilization rate of 1996. During the 46 years of the Reed census, rig fleet utilization through 1998 averaged 73%.
Deletions from the fleet totaled 72 rigs in 1998 vs. 127 in 1997. The main reason cited by surveyed contractors for deletions was capital expenditure requirements exceeding $100,000 for land rigs and $1 million for offshore units. This was the reason for 29 of the rigs dropped from the U.S. fleet in 1998.
Twenty-two rigs were cannibalized or auctioned for parts, 10 were moved out of the U.S., 8 had been stacked for more than 3 years, and 3 were destroyed.
Additions to the fleet totaled 112 in 1998, compared with 143 in 1997.
Sixty-two rigs were assembled from components, 37 were returned to service, 7 were newly manufactured, and 6 were moved into the U.S. in 1998.
In 1997, the biggest gains in the fleet came from rigs brought back into service: 72. Also, the 1998 number of newly manufactured rigs, which totaled only two in 1997, was the highest in a decade.
Three of the newly manufactured rigs were offshore platform units for the Gulf of Mexico. The other four were land rigs.
The number of U.S. contractors owning rigs continued a long decline in 1998, when Reed tallied 240, down 30 from the year before. By comparison, there were 690 rig-owning contractors in 1987.
Reed said 194 rigs changed hands in the interval between its 1997 and 1998 looks at the market.
In a reflection of industry consolidation, the share of the U.S. rig fleet owned by contractors with 20 or more rigs rose to 50% in 1998 from 37% in 1996. The share was only 20% in 1993.
Rig rates were the main concern of contractors surveyed in the 1998 Reed census. A year earlier, rates represented the No. 3 concern behind crew availability and drill-pipe replacement.
In 1998, crew availability was the No. 2 concern and drill pipe replacement No. 3.
Reed forecast a 5% decline in rig activity for 1999, with availability unchanged or down slightly.
1997 spending up
The slowdown of 1998 followed a boom year for spending on U.S. drilling-and in associated costs.
The 1997 Joint Association Survey (JAS), reported by American Petroleum Institute in 1998, showed that total spending on U.S. oil and gas drilling operations rose in 1997 to its highest level in more than a decade.
The industry spent 47% more in 1997 to drill and equip wells than it did in 1996, according to the JAS. Drilling outlays totaled $16 billion in 1997 vs. $10.9 billion in 1996.
Operators completed more wells in 1997 than at any time since the Persian Gulf War year of 1991. Footage drilled in 1997 was its highest since 1988.
The average cost per well and average cost per foot reached their highest levels in 15 years during 1997. The average cost of drilling wells of all types jumped 22% in 1997 to $603,918. The median cost jumped by the same percentage to $603,918. The average cost per foot for wells of all types rose 21% to $107.83.
For oil wells, the average cost per well jumped 31% to $445,613, median cost per well by 29% to $242,000, and average cost per foot by 28% to $90.48.
For gas wells, the average cost per well jumped 18% to $728,600, median cost per well by 20% to $287,000, and average cost per foot by 19% to $117.55.
The average depth of all oil and gas wells and dry holes increased about half a percent in 1997 to 5,601 ft. The oil well average depth rose 2% to 4,925 ft, and the gas well average depth slipped 0.7% to 6,198 ft.
According to the JAS, operators drilled 1,111 horizontal wells at a total cost of $1.1 billion in 1997, about the same as in 1996. The average depth of horizontal wells drilled in 1997 was 7% greater than those drilled in 1996.
U.S. operators spent $4 billion offshore in 1997, double the amount spent in 1996, according to the JAS. Drilling and completion activities in the Gulf of Mexico accounted for 75% of all U.S. offshore outlays in 1997.
Onshore spending for exploratory oil and gas wells shallower than 10,000 ft more than doubled in 1997 from the prior year.
In 1997, operators drilled and completed 668 coalbed methane wells at a total cost of $69 million, accounting for total footage of 935,102 ft.
Survey of executives
An annual, late-year survey by Arthur Andersen reflected near-term pessimism but longer-term optimism for exploration and production in the U.S. Eighty-three companies participated in the 1998 survey, including five major companies, 18 large independent companies, and the rest smaller independents.
The results, by subject:
- Natural gas. More than half (55%) of the respondents expected demand for natural gas to increase by 2-4%/year for the following 5 years. Nearly all the respondents thought the U.S. had significant gas reserves remaining to be found; 36% of them thought the price necessary to increase the reserves base had to exceed $2.50/Mcf, while 43% said an average price of $2.50/Mcf would be needed.
- Crude oil. Fifty-two percent of the respondents said oil demand would increase an average of 0-2%/year in the following 5 years. The share believing significant oil reserves remained to be discovered in the U.S. was 59%. The required average price: 18% said $20-25/bbl; 37% said $20/bbl; and 32% said $16-20/bbl.
- Capital spending. Twenty-nine percent of the respondents said they planned to increase spending on U.S. exploration in 1999, and 46% planned to increase U.S. development spending. Only 16% planned to increase foreign exploration spending, and 19% planned to increase foreign development spending.
Respondents rated the U.S. the most attractive area for investment in exploration and development. Next in the ratings came Canada, the Middle East, and West Africa.
The most important factors in responding companies` capital spending decisions? Projected natural gas prices, followed in order by availability of attractive drilling prospects and projected crude oil prices.
Eighty-one percent of the respondents expected mergers, acquisitions, and divestitures to increase in 1999 from 1998 activity.
- Employment outlook. Seventy-nine percent of the respondents expected a decrease in industry employment in 1999. But only 24% expected to cut exploration and production employment in their own companies in 1999. One third of the respondents said they were experiencing shortage of skilled personnel in their companies.
- Prices. The median expectations for the price of West Texas intermediate crude were $16/bbl in 1999, $17/bbl in 2000, and $19/bbl in 2003. Median expectations for the spot price of natural gas at Henry Hub were $2.25/Mcf in 1999, $2.30/Mcf in 2000, and $2.49/Mcf by 2003.
- Drilling rigs. The median forecast for the U.S. average rig count for 1999 was 800. Eighty-four percent of the respondents did not anticipate a shortage of U.S. offshore drilling rigs in 1999, and 93% expected no shortage of U.S. onshore rigs.
- Key industry issues. Respondents said key issues facing the U.S. exploration and production industry were uncertain oil and natural gas prices and the lack of attractive drilling prospects.
- Value creation opportunities. The respondents indicated that the most opportunity for creating value in their industry came from higher crude oil and natural gas prices and reduced finding costs.
REFining trends
U.S. refiners in 1998 passed a major milestone in their introduction of reformulated gasoline (RFG) in major markets and prepared to pass another one in 2000.
The Clean Air Act Amendments of 1990 required RFG in areas not in attainment with federal air quality standards for ozone. The basic requirement for RFG began on Jan. 1, 1995.
The 1998 milestone was a requirement, which took effect at the beginning of the year, that all refiners calculate RFG emissions with what was known as the complex model for calculating gasoline emissions based on product qualities. They earlier had their choice between a simple model and early-use complex model.
All the models incorporated a baseline for determining quality limits, designed to prevent the dumping into conventional gasoline of polluting substances removed from RFG. Refiners had been able to calculate their own baselines based on 1990 gasoline quality or use a statutory guideline, which was more strict. Most used their own baselines.
The complex model that all U.S. refiners had to meet as of Jan. 1, 1998, calculated emissions on the basis of eight gasoline parameters: oxygen, sulfur, Reid vapor pressure, percent evaporated at 200° F. (E200), E300, aromatics, olefins, and benzene. The complex model set ranges for each parameter.
The simple model had used only oxygen, benzene, and Reid vapor pressure as parameters. While the complex model`s tolerances were more strict than the simple model`s for some parameters, switching to it gave refiners greater flexibility in meeting emissions standards than they had under the simple model.
At least two refiners had adopted the complex model before it became mandatory in 1998.
Stricter standards were due on Jan. 1, 2000, when the so-called Phase 2 complex model was to take effect.
The Phase 2 complex model essentially tightened standards for calculated emissions of nitrogen oxides, volatile organic compounds, and toxic compounds. The most significant change was thought to be a 5-7% reduction of NOx in summer.
The general way to reduce NOx in gasoline blending was to reduce sulfur or olefins, although refiners faced tradeoffs. Cutting olefins, for example, could increase calculated emissions of volatile organic compounds.
REFiners therefore were expected to concentrate on sulfur. Some of them would be able to meet the Phase 2 RFG challenges largely by lowering the average sulfur content of their feedstock crudes.
For others, that wouldn`t be enough. They were likely to have to increase hydrotreating of feed streams to fluid catalytic cracking units-the major contributors to gasoline sulfur-or hydrotreating the gasoline produced by them.
Before introduction of the Phase 1 complex model, U.S. gasoline contained an average 340 ppm of sulfur. According to one estimate, gasoline sulfur content would have to fall to 100-150 ppm to meet Phase 2 RFG requirements.
Some refiners were expected to turn to alkylation of C5 olefins to reduce NOx emissions, although C5 olefins were not thought to constitute as good a feed to alkylation as the more traditional C4 olefins.
Among other issues raised by the Phase 2 requirements was a cut against baselines of about 10% in calculated emissions of volatile organic compounds. Refiners in the U.S. South were expected to have bigger problems with that requirement than their northern counterparts because they had already removed butanes to meet the earlier standards for Reid vapor pressure. To meet further reductions they faced having to remove pentanes-and to find something to do with them.
MTBE issue
While they sought ways to meet the toughening standards for RFG, U.S. refiners faced another challenge in 1998: growing public resistance to their use of methyl tertiary butyl ether (MTBE).
REFiners added MTBE to gasoline to boost octane and to meet a federal requirement that RFG contain 2 wt % oxygen. They had other oxygenates to choose from, including ethanol and ethyl tertiary butyl ether. But MTBE had been their overwhelming favorite for economic reasons.
MTBE ran into early problems when motorists in Wisconsin and Alaska complained that RFG containing MTBE made them ill. Those complaints received no substantiation in health tests.
Later, however, MTBE began showing up in ground water, including some used for drinking. In most cases, concentrations were well below advisory levels the Environmental Protection Agency set for taste and odor. But in a couple of highly publicized instances in California, large leaks of gasoline containing MTBE resulted in severe contamination of drinking water.
The EPA resisted calls for a ban on the oxygenate but formed a committee of 14 health and industry experts to study MTBE and other oxygenates.
Congressional representatives from California introduced legislation in 1998 that would have waived the oxygenate requirement for the state`s RFG, which met stricter standards than RFG sold elsewhere. The legislation would have allowed refiners to use either ethanol-based oxygenates or no oxygenates at all as long as the resulting gasoline met other emissions and content standards.
Tosco Corp. began a pilot program to market gasoline free of MTBE in three northern California counties. It sold gasoline produced at its Rodeo, Calif., refinery and blended with ethanol in 50 retail outlets.
Capacity changes
One refinery closed, and another one started up in the U.S. during 1998.
In November, Equilon Enterprises LLC, a venture of Shell Oil Products Co. (56%) and Texaco Inc. (44%) shut down its 28,300 b/cd Odessa, Tex., refinery.
In June, Trans-American Refining Corp.`s 200,000 b/cd refinery at Norco, La., began receiving crude in its distillation towers. The refinery, originally called Good Hope, had been shut down in 1983.
Total U.S. refining capacity increased to 16,422,700 b/d as of Jan. 1, 1999, from 15,898,400 b/c a year earlier.
Restructuring changed ownership of U.S. refineries during the year.
Equilon Enterprises resulted from a merger involving Shell, Texaco, and Star Enterprise, a combine of Texaco and Saudi Arabian Oil Co. (Saudi Aramco). Equilon covered the midwestern and western U.S. refining and marketing activities of the companies involved and all U.S. transportation, trading, and lubricants businesses. Not included was Shell`s Deer Park, Tex., refinery, which the company owned jointly with Petroleos Mexicanos.
To meet federal antitrust concerns, Equilon had to divest Shell`s Anacortes, Wash., refinery. Tesoro bought the facility.
Another entity resulting from the same three-way merger was Motiva Enterprises LLC, owned 35% by Shell and 32.5% each by Saudi Aramco and Texaco. Star Enterprises became obsolete.
Motiva comprised four refineries in Port Arthur, Tex., Convent, La., Norco, La., and Delaware City, Del.
Also in 1998, Phillips Petroleum Co. proposed to merge its North American refining, marketing, and transportation operations with Ultramar Diamond Shamrock.
In January 1998, the merger of refining operations of Marathon Oil Co. and Ashland Oil Co. resulted in the formation of Marathon Ashland.
REFining strategies
At the Arthur Andersen energy symposium in December 1998, Jean Gaulin, vice-chairman, president, and chief operating officer of Ultramar Diamond Shamrock, traced an evolution of refining industry strategies that led to the consolidations of the late 1990s.
In the 1980s, he noted, falling gasoline demand and stable capital requirements lowered refining margins and returns and encouraged refiners to shut down refineries and increase operating rates. By the end of the decade, margins and returns had improved.
After the mild recession of 1990-91, gasoline demand growth stabilized, and capital investment requirements rose because of requirements imposed by the Clean Air Act Amendments of 1990. Gasoline production also increased.
An early strategy was to continue shutting down refineries and increasing operating rates.
"That solution doesn`t work anymore because we`re fully utilized," Gaulin said.
Product imports limited margin improvements and returns, meanwhile, forcing refiners to consolidate.
"We have to merge and reduce costs so we can live with those low margins," Gaulin said.
Company mergers
REFining combinations were by no means the only merger activity in 1998.
In December, Exxon Corp. and Mobil Corp. announced a merger that, if approved in 1999, was to be the largest industrial merger in history. The resulting Exxon Mobil Corp. would surpass Royal Dutch/Shell to become the largest oil company and the world`s largest corporation.
Exxon Mobil, to be based in Irving, Tex., would be owned 70% by the former Exxon and 30% by Mobil. Estimates of value of the deal ranged from $70 billion to $77 billion.
At the time of the merger announcement, Exxon had annual net income of $8.5 billion on revenues of $137.2 billion with capital employed of $52.9 billion. Mobil had net income of $3.3 billion on revenues of $65.9 billion with capital employed of $26.5 billion.
Exxon had worldwide net production of 1.6 million b/d of crude oil and NGL and 6.3 bcfd of natural gas. Its liquids reserves totaled 6.8 billion bbl, its gas reserves 42.1 tcf. Exxon`s worldwide refinery throughput was 4 million b/d.
Mobil had worldwide net production of 900,000 b/d of crude and NGL and 4.6 bcfd of gas. Its reserves totaled 4.1 billion bbl of liquids and 17 tcf of gas. Refinery throughput was 2.1 million b/d.
Less than 5 months earlier, British Petroleum Co. plc and Amoco Corp. agreed to a merger of the U.S. company into BP.
The merger occurred at the beginning of 1999 with BP holding 60% equity interest and Amoco 40% in the surviving company, BP Amoco plc, based in London.
The companies had combined market capitalization of $110 billion. Together, they had reserves of 14.8 billion bbl of oil equivalent, production of 2.9 million b/d of oil equivalent, and net refining capacity of 2.7 million b/d.
The deal`s value was estimated at $48 billion.
Among other large U.S. combinations of oil and service companies 1998, Halliburton acquired Dresser Industries in a deal valued at $7.7 billion, Baker-Hughes acquired Western Atlas ($5.5 billion), Schlumberger acquired Camco ($3.14 billion), Kerr-McGee acquired Oryx ($2.98 billion), EVI acquired Weatherford Enterra ($2.6 billion), UPRG acquired Norcen ($2.41 billion), and Ocean Energy merged with Seagull ($1.4 billion).
Federal issues
The most hotly debated federal issue of 1998 was a proposal by the Minerals Management Service to reform the way values are determined for oil in calculating the federal royalty from offshore production.
MMS based its reform initiative on the assertion that reliance on refiners` posted prices undervalued crude oil and therefore suppressed the government`s royalty take. Producers` groups, acknowledging that market changes had eroded the usefulness of postings in broad determinations of value, recommended that the government take its royalty in kind. That, they said, was the best way to determine value.
MMS strongly opposed a royalty-in-kind option. It argued that the government would lose money overall if it-or, more likely, a contract agent-took possession of the oil and resold it. It further argued that evaluation for royalty purpose should take place downstream of the lease so that the government, in effect, could capture value associated with initial movements of the oil. Producers objected to that interpretation.
The MMS proposal was to use an index based on futures market prices, adjusted for location and crude quality, for much of the oil produced on federal offshore leases. The industry argued that such an index would be unrealistic and a step away from valid oil valuation.
The issue carried over from 1997, when an amendment to an appropriations bill blocked MMS implementation of the rule to give the agency and industry groups time to seek a compromise. MMS would not change its position on the issue, however, and the compromise effort failed.
The rule would have taken effect at the beginning of the federal government`s 1999 fiscal year on Oct. 1, but another appropriations bill amendment postponed the effective date for 8 months. By then, what amounted to an economic dispute had become fiercely political, with liberal Sen. Barbara Boxer (D-Calif.) at one point declaring, "Big oil companies have been cheating American taxpayers out of royalty payments for years" and complaining that schoolchildren in her state were "being denied funding that could be used for computers, textbooks, or hot lunches."
Her charges brought a rebuke from Sen. Craig Thomas (R-Wyo.), who said he was offended by them. "This amendment is not about schoolchildren," he said.
The MMS effort received a potential setback later in the year, when Director Cynthia Quarterman announced her resignation effective in February 1999. Quarterman had led the reform effort and held fast to the MMS position in the unsuccessful attempt at compromise.
NPR-A leasing
In October 1998, the Department of Interior formally accepted a plan to open a section of the National Petroleum Reserve-Alaska (NPR-A) for oil and gas leasing. A lease sale was possible in mid-1999.
The reserve had been established 75 years earlier as a source of oil for the U.S. Navy. The area had been partly leased and drilled in the early 1980s. The prior lease sale, in 1984, attracted no bids.
Interior`s Bureau of Land Management (BLM) was to make available for leasing 87% of the 4.6 million acre northeastern quadrant of the NPR-A. BLM estimated that the entire quadrant held a recoverable oil resource of 500 million-2.2 billion bbl.
NPR-A lies west of Prudhoe Bay oil field on Alaska`s North Slope.
Interior`s leasing plan included restrictions. It prohibited surface disturbance on one third of the area with "sensitive wildlife habitats" but allowed directional drilling to targets beneath them. It also barred leasing in certain areas.
Industry groups regretted the restrictions.
American Petroleum Institute said the plan "unfortunately fails to recognize the enormous strides in arctic environmental protection made by the oil and gas industry."
Independent Petroleum Association of America said Interior should have opened more land for lease.
Electricity legislation
The Department of Energy in March 1998 sent Congress legislation aimed at extending federal deregulation of the electric power industry to the retail level. In a series of rulemakings, the Federal Energy Regulatory Commission had deregulated generation and sales at the wholesale level and left retail deregulation to the states. By year-end 1998, 18 states had acted to open retail sales to competition.
Congress didn`t act on the DOE legislation, called the Comprehensive Electricity Competition Act, in 1998, although later action was possible. Under the proposal:
- All electric consumers would be able to choose suppliers by Jan. 1, 2003, although states would be able to opt out of retail competition if they believed consumers would benefit more from existing conditions or their own plans.
- The secretary of Energy would be able to require all retail electricity suppliers to disclose information on prices, terms, and conditions of service; type of primary energy used for generation; and the environmental attributes of the generation.
- The government would establish a "renewable portfolio standard" to ensure that by 2010 at least 5.5% of all electricity sales involved power generated from renewable energy sources.
- A "public benefit fund" would be established to provide matching funds of as much as $3 billion to states for low-income assistance, energy-efficiency programs, consumer information, and development and demonstration of emerging technologies, especially those involving renewables.
- FERC would have authority to require transmitting utilities to turn over operational control of transmission activities to an independent system operator.
- The federal government would encourage states to allow for the recovery of prudently incurred, legitimate, and verifiable retail stranded costs not reasonably mitigated by other means.
- All participants in transactions on the transmission grid would comply with mandatory reliability standards overseen by a private, self-regulating organization set up by FERC.
- Federal electricity law would be changed to achieve competition without market abuse, including repeal of the Public Utility Holding Company Act of 1935 and the "must buy" provision of the Public Utility Regulatory Policies Act of 1978. FERC would address market power.
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