CAPITAL: Washington, D.C.
MONETARY UNIT: Dollar
REFINING CAPACITY: 15.9 million b/d
OIL PRODUCTION: 6.4 million b/d
OIL RESERVES: 22 billion bbl
GAS RESERVES: 166.5 tcf
An upstream recovery that began at mid-decade in the U.S. encountered the inevitable in 1997. Rising activity levels strained supplies of oil field equipment, materials, services, and people. In response, costs rose in a trend that seemed destined to continue.
While it hardly threatened to reverse the upswing in oil field activity, the cost bounce meant that the recovery had entered a new phase. Cost reduction was one of two main ingredients of the upstream rebound, the other being steady growth in demand for oil products and natural gas.
Strategic cost-cutting was a natural and essential response to the declines in prices of oil and natural gas that occurred in the mid-1980s, eroding upstream profitability. But a cost jump was just as natural a response to the rising activity of the mid-1990s. The ability of the industry to absorb rising costs for discrete economic inputs such as drilling services, tubular supplies, and labor promised to test the productivity gains that producers had made with improvements in organization, practice, and technology.
The Houston Branch of the Federal Reserve Bank of Dallas analyzed the trends in reports published at the end of 1997.
It pointed out that by 1995 efficiency improvements had enabled the U.S. upstream industry to work profitably with the crude oil price at $17/bbl and the gas price at $1.70/Mcf. With prices in 1996-97 closer to $20/bbl and $2/Mcf, the industry was thriving and plowing much of its earnings back into drilling. In 1996, the number of oil and gas wells drilled in the U.S. jumped 22%, and in late 1997 the total was running nearly 18% ahead of the 1996 level.
The Houston Fed pointed to an apparent paradox in U.S. upstream costs. During 1988-96, real capital investment per foot drilled increased by 13%. Yet the cost of finding and developing a barrel of oil fell by 20% in roughly the same period-from $5.50/bbl in 1986 to $4.40/bbl in 1996 (Fig. 1).
The explanation was increased productivity. While the industry was spending increasing amounts of money to drill each foot of hole, it was adding to oil and gas reserves at an even faster rate for each foot drilled (Fig. 2). The volume of reserves added more than offset the higher costs.
The question for years beyond 1997 was whether the technological dimension of productivity improvements could offset the cost increases that were certain to continue if upstream activity kept expanding.
The Houston Fed pointed out that a 50% increase in day rates for land rigs between mid-1995 and the last quarter of 1997 showed that a decade-long rig surplus had ended. But day rates would have to rise even more to stimulate construction.
Using data from a Sept. 22, 1997, article in Oil & Gas Journal, the Fed noted that a 2,000 hp land rig capable of drilling to 20,000 ft would cost $12.5 million to build. To return 15% to capital, the rig would have to receive a rate of $16,600/day, about twice the market level at the time of the analysis. And the producers using the rig would demand a comparable return on capital.
"Whatever the long-term wisdom of oil industry expansion may be," wrote the Houston Fed in November 1997, "it is clear that such growth would come at higher drilling and finding costs than those enjoyed even today."
The industry`s increasing reliance on technology had another cost-related effect that became evident in 1997: "Relative to basic measures of activity, the industry has become more labor-intensive," the Houston Fed noted.
Total wages per foot drilled paid to employees subject to wage and salary laws by producers and service companies increased after 1985. In 1995, according to the Fed, producers paid 90% more in wages per foot drilled than they did in 1985. Service companies paid 16% more.
To take in workers exempt from wage laws, the Fed counted the number of jobs and came to similar results. By 1995, it said, the number of jobs was up 54% per foot drilled for producers and 92% for oil service companies.
Again, technology explained the increase in labor inputs per foot of drilling that came while overall industry employment was declining from a peak of 812,000 in 1982 to 365,000 in 1997-about the level of 1975.
The industry in 1997 performed more upfront geological and geophysical assessment before drilling than it did a relatively few years earlier. And it drilled wells that were more expensive, increasingly favoring horizontal and offshore wells and using innovations such as coiled-tubing and measurement-while-drilling techniques. The new predrilling and drilling practices improved success ratios and raised finding rates. They also increased skill requirements in the industry and raised the number of hours expended per foot of drilling.
The elevated labor intensity explained how the industry could be running into labor constraints in 1997 where, just months earlier, it was still shedding workers.
"A sharp, short-run increase in the number of wells drilled now implies a much sharper rise in the number of hours to be worked," the Fed said. "Seemingly overnight, the industry is working 24 hr a day to overcome shortages of machinists, welders, geophysicists, and managers in assessing and directing projects."
The Fed further asserted that to sustain the upstream expansion in the U.S., oil and gas prices would have to rise enough to attract not only capital to the industry but also labor.
"The inventory of excess oil field skills-like that of the surplus rigs from the 1980s-is now exhausted," it said. "Employees are no longer a subsidized and expandable commodity. Expansion from now on would entail higher wages, intensive training, and the development of specific industry skills."
Prices decline
The cost increase came in year with a tail-end skid for oil and gas prices.
In the first week of December 1997, the New York Mercantile Exchange futures price for light, sweet crude delivered the following month averaged $18.71/bbl, $6.44/bbl less than its level in the same week a year earlier.
Some of the change reflected unusual price strength at the end of 1996, when inventories were tight. At the end of 1997, crude stocks were 5.4% above year-earlier levels, gasoline 1.9% higher, distillate 10.4% higher, and jet fuel 14% higher. Only resid stocks were below year-earlier levels.
Crude prices also had been weakened by a November agreement by the Organization of Petroleum Exporting Countries to raise its group quota in a move that essentially made official what already was happening due to quota violations. Because of the newly sanctioned elevation in OPEC output, expected increases in production from outside the producers` group, and expectations for a slowdown in worldwide demand growth, oil price weakness was expected to extend into 1998.
Natural gas prices, after exceeding $3.50/Mcf on the Nymex during the first half, also slumped toward the end of the year. The average price in the first week of December was $2.60/MMBTU on the Nymex vs. $3.48/MMBTU the same week a year earlier.
Some of the weakness reflected the end in November of the storage build season and the beginning of the period in which inventories normally complement U.S. production and Canadian imports as a source of U.S. supply.
On a degree-day basis, 1997`s heating season began, in November, colder than normal but warmer than 1996`s season, which also accounted for some of the late-year price slump.
The rig market
Rising activity levels reversed a long slide in the U.S. rig market as reflected in the 1997 annual rig census by Reed Tool Co. Reed reported census findings at the annual meeting of the International Association of Drilling Contractors in October.
After 14 straight years of decline, the number of available rigs increased in 1997 from an all-time low in 1996. The available count in the 1997 census was 1,665 units, up 16 from the 1996 total.
And active rigs, by the Reed method of counting, increased nearly 15% from the 1996 level to 1,447 units. The Reed measure is a cumulative count of all rigs active at any time during a defined 45 days of summer.
Fleet utilization, which compares active to available rigs, jumped to 87%, the highest level since the boom year of 1981. The 1996 utilization rate was 77%. Before the 1997 increase, the utilization rate since 1981 had averaged about 73%.
There were 127 deletions from the 1997 Reed census of available rigs. Fifty-eight of the deletions were due to capital expenditure requirements exceeding $100,000 for land rigs and $1 million for offshore rigs. Reed raised those thresholds from $50,000 in previous years.
Deletions also included 28 rigs cannibalized or auctioned for parts. It was the second year of decline in the number of cannibalizations. Reed said the decrease indicated depletion of this low-cost source of replacement equipment.
Other fleet reductions were 18 rigs that moved out of the U.S., mostly to Canada and Latin America; 17 rigs stacked more than 3 years; and six rigs damaged beyond repair.
Fleet additions totaled 143 in 1997, more than twice the number in 1996. Rig owners reactivated 72 rigs that had been dropped from earlier census totals, assembled 57 rigs from components, moved 12 rigs into the U.S., and built two units.
The two newly built rigs were a barge unit and a platform rig for the Gulf of Mexico.
The reactivation total was more than twice the 1996 number, which indicated that a large number of rigs deleted from the fleet earlier were not cannibalized and remained available for recycling into use. Similarly, the number of assemblies from components in 1997 was up sharply from the 24 recorded in 1996.
In a survey conducted at the time of the census, contractors told Reed that rig rates were up an average of 20% for the year. Daywork drilling was up 11%.
Contractors responding to the survey said their biggest concern was the shortage of skilled labor. They reported raising wages by an average of 11% in 1997.
Their second concern was a shortage of drill pipe, and their third, rig rates that they considered insufficient to attract capital.
Survey of executives
Another indication of the exploration and production industry`s outlook came in December 1997 when Arthur Andersen reported findings of an annual survey it conducts of oil company executives. The 1997 survey included 94 companies.
The key findings, as reported by Arthur Andersen:
- Natural gas. Fifty-seven percent of the respondents predicted that U.S. natural gas demand would increase by 2-4%/year through 2002. Ninety-one percent of them said they believed that significant reserves remained to be discovered in the U.S., with 43% saying that the gas price had to exceed $2.50/Mcf if the reserves base was to grow.
- Crude oil. Fifty-five percent of the respondents expected demand for oil in the U.S. to average 2-4%/year through 2002. Seventy-one percent of them believed that significant oil reserves remained to be found in the U.S., with 38% saying the average crude oil price had to be at least $25/bbl for reserves expansion to occur.
- Capital spending plans. More than 70% of the surveyed executives planned increases in both U.S. exploration (72%) and development (73%) spending in 1998. Outside the U.S., 45% planned to increase exploration spending, and 38% planned to increase development outlays in 1998. Respondents rated the U.S. the most attractive area for investment in oil and gas exploration and development. Venezuela, Argentina, and Canada were close behind in the ratings. Respondents considered attractive drilling prospects the most important factor in capital spending decisions. Their second most important factor was oil and gas prices. Seventy percent of the executives believed that mergers, acquisitions, and divestitures would increase in 1998.
- Employment outlook. Ninety-percent of the respondents expected an increase in industry employment in 1998; 78% expected to increase exploration and production employment in their own companies during 1998. Fifty-nine percent of the respondents reported experiencing shortages of skilled personnel at the time of the survey.
- Price forecasts. The combined outlook of the executives for the price of West Texas Intermediate crude was $20/bbl in 1998 and 1999, rising to $21.50/bbl in 2002. The outlook for natural gas prices at Henry Hub in Louisiana was for a median of $2.30/Mcf in 1998 and 1999 and an increase to $2.50/Mcf by 2002.
- Drilling rigs. The median expectation of surveyed executives for the 1998 active rig count was 1,000. Eight-two percent of the executives expected a shortage of U.S. offshore rigs in 1998, while 54% expected a shortage of onshore units.
- Key industry issues. The respondents said the most significant issues facing the U.S. exploration and production industry were uncertain natural gas and oil prices and lack of attractive drilling prospects.
- Value creation opportunities. Areas with most opportunity for creating value, according to the surveyed executives, were higher natural gas prices, improved drilling success rates, and higher crude oil prices.
Reserves trends
Effects of revived activity in the U.S. offshore, especially the Gulf of Mexico, appeared in total reserves estimates reported by the federal government`s Energy Information Administration in September 1997.
Natural gas reserves in 1996 increased for the third consecutive year, EIA said. And oil reserves, while extending their period of decline to 9 years, fell by only 1%, to 22 billion bbl.
GAS reserves increased by 1% to 166 tcf.
For gas, additions to reserves amounted to 107% of total production.
Total discoveries of dry gas reserves exceeded 12 tcf in 1996, increasing by 12% over the 1995 level. More than two thirds of the total was in Texas and in federal waters of the Gulf of Mexico. Exploratory gas well completions increased to 972.
New-field gas discoveries totaled 1.5 tcf in 1996, a decline from 1995 but 10% higher than the average of the previous 10 years.
Revisions and adjustments to reserves estimates of old fields added a net 8 tcf to reserves in 1996.
For crude oil, total additions to reserves represented 85% of 1996 production.
Total discoveries were nearly 1 billion bbl, slightly below the 1995 level but about 40% higher than the prior 10 year average. Federal acreage in the Gulf of Mexico accounted for 34% of total discoveries, Alaska 21%, and Texas 18%.
New field discoveries totaled about 250 million bbl, more than twice the 1995 total and the prior 10 year average. Alaska had 53% of the new field discoveries in 1996 and the federal Gulf of Mexico, 39%.
Drilling activity
Early in 1998, Oil & Gas Journal predicted a drilling slowdown for the year. In addition to rising costs, the magazine cited a worldwide sufficiency of crude oil, weakening oil and gas prices, and the economic effects of the currency crisis in Asia.
OGJ predicted drilling of 25,900 wells in the U.S. in 1998, down from an estimated 26,850 in 1997 but higher than in any of the 4 years before that. It expected the weekly Baker Hughes rig count to average 900 vs. 945 the year earlier.
It forecast drilling of 3,315 exploratory wells of all types, down from 3,466 in 1997.
The magazine assumed that, with oil and gas prices sagging, wellhead revenues would drop 7.4% from the 1997 level to a total of $80.06 billion. That would still be above the average for the 5 years ending in 1998.
OGJ predicted spending for drilling and completion at $13.828 billion in 1998, higher than the average of the preceding 5 years.
Footage in the OGJ forecast would total 155 million ft of hole, or 5,985 ft/well. Averages based on these predictions are $533,900/well and $89.21/ft, including offshore-2.5% more per well than in 1997 and 2.7% more per foot.
The average rig count for 1997 was up 20% from that of 1996, with half the increase coming in Texas, where the 356 rigs/week average was up 72 from the year earlier.
Wyoming`s 1997 rig count averaged 39, up 15; Louisiana`s, including the Gulf of Mexico, 191, up 34; New Mexico 52, up 18; Kansas 19, down 5; and Oklahoma 104, down 2.
Area trends
An important trend gaining momentum in the onshore Lower 48 in 1997 was concentration by large companies or joint ventures on specific regions in which the companies or partners held large acreage positions.
An example was Altura Energy Ltd., formed in 1996 and beginning operations in 1997 as a combination of the Permian basin assets of Shell Oil Co. and Amoco Corp.
After Altura began operations, Amoco announced plans to divest reserves totaling 460 million bbl of oil equivalent and production totaling 70,000 b/d of oil equivalent in western basins outside the Altura JV. Amoco said it was not abandoning the U.S. but rather focusing on growth opportunities such as those in the deepwater Gulf of Mexico.
Conoco Inc. in 1997 paid $900 million to buy gas reserves, production, and assets in the Lobo trend of South Texas from GATX Corp.`s First Intercontinental Leasing Trust, adding to a strong position it already held in the area. Conoco planned to invest more than $1 billion during 5 years to develop gas reserves estimated at 2.7 tcf. The acquisition included 215,000 acres, 1,100 wells, 250 bcf of proved and 1.8 tcf of proved plus estimated reserves, and 1,100 miles of gathering and transmission pipelines.
The properties formerly had been owned by the TransTexas Gas Corp. unit of TransTexas Transmission Corp. TransTexas planned to use proceeds to focus on other properties in South Texas, including Bob West North and Fandango South fields, and on the Lodgepole play in North Dakota, where it planned to accelerate development activity.
In another regionally oriented joint venture, Shell Oil`s CalResources LLC unit and Mobil Exploration & Production U.S. Inc. combined their California exploration and production operations to form the state`s largest oil producer. The venture, Aera Energy LLC (58.6% Shell and 41.4% Mobil), began operating June 1, 1997, with proved reserves of more than 1 billion bbl of oil equivalent and production of about 250,000 b/d of oil equivalent. CalResources and Mobil had conducted adjacent operations in Kern County`s Belridge and Midway-Sunset fields.
Two independent producers merged in 1997 to form the third largest independent exploration and production company in the U.S. Mesa Inc. and Parker & Parsley Petroleum Co. combined to form Pioneer Natural Resources Co. with reserves of 1.7 tcf of natural gas and 293 million bbl of crude oil and liquids.
Some key plays
Among important onshore Lower 48 action in 1997, the Jurassic Cotton Valley pinnacle reef play of East Texas was moving northward.
The play began with a 1980 discovery by TXO Production Co. but did not begin hitting stride until 1993, when Marathon Oil Co., which acquired TXO, made its 1 Poth Family Trust discovery in Leon County. Three dimensional seismic techniques then becoming available proved essential to the deep, narrow drilling targets. In general, companies identified reef tops as dim spots in 3D seismic data.
In addition to being difficult to target, the reef wells presented big drilling challenges, including overpressures, high temperatures, and troublesome concentrations of hydrogen sulfide and carbon dioxide. Operators usually used one well per reef to produce reserves of 20 bcf and more per reef. They usually encountered the reefs at 14,000-15,000 ft.
Most reef drilling in 1997 centered on Robertson, Leon, and Freestone Counties, which were leased up. But 3D seismic surveys were under way on trend to the north in Anderson, Henderson, Van Zandt, Smith, and Wood counties.
By mid-1997, reef production had increased to about 200 MMcfd from a yearend 1996 average of 133 MMcfd. Delhi Gas Pipeline Corp., which handled all production in the play, expected output to reach as high as 300 MMcfd by yearend and was expanding its gathering and treating capacity to handle the increase.
Meanwhile, non-reefal Cotton Valley targets, long a source of activity along the U.S. Gulf Coast, received new attention in southeastern Mississippi during 1997. Operators using 3D seismic had made discoveries with initial test rates of 500-1,000 b/d of oil in an area covering Clarke, Jasper, Wayne, Jones, Covington, Smith, and northern Perry counties and were looking at Cotton Valley potential in a wide band from there to the west-central part of the state.
The Cretaceous Austin Chalk horizontal drilling play remained active from Southeast Texas into Louisiana and yielded some huge flow rates.
In the deep Giddings field area of Washington County, Tex., Chesapeake Energy Corp. and Belco Oil & Gas Corp. reported that their 1-H Brown single-lateral well flowed 100.3 MMcfd of gas through a 48/64-in. choke with flowing tubing pressure of 5,025 psi. The well was drilled to 14,600 ft true vertical depth and had lateral displacement of almost 3,900 ft.
It was believed to be the largest flow rate from a U.S. horizontal well.
Union Pacific Resources Group Inc. had another big producer in the area, 1 Eberle, which produced 84.7 MMcfd. By second quarter 1997, UPR`s Washington County production had quintupled in 2 years to 239 MMcfd from 20 wells operated by the company.
In Louisiana, Austin Chalk production remained within a relatively narrow region between Burr Ferry North field in Vernon Parish near the border with Texas and nearby Masters Creek field in Rapides Parish. But drilling was active.
Outside Texas and the Gulf Coast, the Williston basin enjoyed another of several years of revival in 1997, although the focus of attention was shifting.
Mississippian Lodgepole reefal targets around Dickinson, N.D., led a drilling resurgence in the big basin several years earlier. By 1997, the B member of the Ordovician Red River formation had become a central target.
The Lodgepole play slowed due to salt deposits hindering the seismic interpretation on which the activity depended. The Red River B play was heavy in Bowman and Slope counties, N.D., Harding County, S.D., and Fallon County, Mont., with completions ranging from 100 b/d/well of oil to more than 400 b/d.
Elsewhere, the northeastern Powder River basin of Wyoming became a drilling hotspot with operators targeting methane in Cretaceous Fort Union coals. Early in 1997, about 240 Fort Union wells were producing around Gillette in Campbell County, and drilling was spreading into Big Horn and Rosebud counties, Mont.
The drilling was within 10-12 miles of and downdip from large open pit sub-bituminous coal mines. Wells into the shallow Fort Union coal could be drilled for about $35,000 apiece.
Two independent producers made an interesting transition zone discovery in western Galveston Bay about halfway between Houston and Galveston.
TransTexas Gas Corp. and Davis Petroleum Corp. said proved, possible, and probable reserves might exceed 1 tcf of gas in a fault block cut by the discovery well, TransTexas 1 State Tract 331. The field, Eagle Point, lies in 7-10 ft of water about 1 mile off San Leon.
The strike flowed 76.4 MMcfd of gas and 11,000 b/d of crude and condensate through a 48/64 in. choke with 7,600 psi flowing tubing pressure from 101 ft of net Oligocene Upper Vicksburg pay. A lower, 60 ft pay zone wasn`t tested because of mechanical problems.
TransTexas planned to test the lower zone in a second well it was drilling early in 1998. It had a 75% interest in the field, Davis Petroleum the remainder.
California disappointment
Off California, once-promising Point Arguello oil field in the Santa Barbara Channel moved toward an earlier-than-expected demise in 1997. Operator Chevron Corp. and partners agreed to unitize the field, adding Texaco Exploration & Production Inc.`s Platform Harvest to their Platforms Hermosa and Hidalgo.
The move was an attempt to keep the field profitable for the last 3 years or so of its productive life.
Leaseholders soon after the discovery in 1981 thought Point Arguello would yield as much as 500 million bbl of oil. By 1996 the estimate had been cut to less than 200 million bbl. Production began in 1991 at 80,000 b/d but had fallen to 30,000-40,000 by early 1997.
The field required 10 years and $2.5 billion to bring on stream and faced regulatory delays, political challenges, lawsuits, and environmental complications at nearly every step. Transportation of oil to California refineries produced a long controversy.
Ray Galvin, president of Chevron U.S.A Production Co., said the experience taught the company a stern lesson.
"I can`t think of a situation in which we would invest in another project offshore California," he said.
Government
Activity by the U.S. government in 1997 included a step toward privatization, American-style, as the Department of Energy prepared to sell the 78% federal interest in Elk Hills field, Kern County, Calif., to Occidental Petroleum Corp. for $3.65 billion. The field had been set aside in the early 1900s as a source of oil for the Navy. In 1997 it produced 60,000 b/d of oil and 400 MMcfd of natural gas. Chevron U.S.A. Production Co. owned the other 22% interest.
The Elk Hills sale was to be complete in February 1998.
In a related issue, Interior Sec. Bruce Babbitt expected to decide in mid-1998 whether to allow leasing of acreage in the northeast corner of the Alaska National Petroleum Reserve (NPR-A). The prospect of leasing part of the reserve arose when the industry disclosed discoveries to the east. NPR-A is west of supergiant Prudhoe Bay field on the North Slope.
The decision was a touchy one for Babbitt, who staunchly opposed leasing of the Arctic National Wildlife Refuge Coastal Plain east of Prudhoe Bay.
The Interior secretary was a central figure in a lawsuit filed against the federal government over President Bill Clinton`s September 1996 designation of 1.7 million acres in south-central Utah as a national monument. The designation was widely regarded as an election year move for political support from environmentalists.
It threatened to withdraw from mineral leasing land that had been reviewed for withdrawal earlier but found to lack statutorily required wilderness characteristics. In 1997, the Utah School and Institutional Trust Lands Administration (Usitla) filed suit challenging the legality of Clinton`s action, which created the Grand Staircase-Escalante National Monument.
Usitla, which administers 176,000 acres of school trust lands and 25,000 acres of trust mineral lands in the monument area, collects more than $100,000/year from the activities for Utah schools. It alleged in its suit that designating land as a national monument was an abuse of presidential authority and that it skirted laws governing withdrawal of land from multiple use. It further alleged that Babbitt maneuvered Clinton into taking the action as a way to prevent opening of an underground mine on the Smoky Hollow prospect in the Kaiparowits coal field.
The monument designation jeopardized leases held by Conoco Inc. and partner Rangeland Exploration Inc. covering more than 100,000 acres of federal and trust land in the monument. Conoco had staked two wildcats in the area. The government indicated in 1997 that Conoco would be allowed to drill on its leases.
The Interior Department`s Minerals Management Service made two proposals in 1997 that drew sharp rebukes from the industry.
One of the proposals would overhaul the way production from federal leases is valued in calculations of the federal royalty. It stemmed from an investigation in which MMS initially claimed to have been underpaid by 19 oil companies a total of $435.6 million on production from leases in California during 1980-88. It later reduced the underpayment claim to $345.5 million. Two of the companies sued MMS, and 17 appealed to the Interior Department.
MMS proposed to base the value of most production from federal leases on the crude oil futures contract traded on the New York Mercantile Exchange (Nymex), with adjustments for location and crude quality. The industry strongly objected, insisting that the Nymex price was an invalid proxy for individual crudes. MMS eventually allowed independent producers to use gross proceeds from arm`s length transactions for royalty valuation, which was essentially the original practice. And at the end of 1997 it was holding discussions with industry groups and considering a revised notice of proposed rulemaking on the subject.
Industry groups generally urged MMS to take the federal royalty in kind rather than in cash amounts determined by proxy transactions.
In another move, MMS changed rules governing the permitting and licensing of geological and geophysical (G&G) data and information in the gulf. When the initiative was proposed in February, geophysical contractors argued that it would require the rewriting of license agreements, add to administrative burdens, and compromise confidentiality of licensed data.
The proposal would have required notification whenever geophysical data were analyzed, processed, or interpreted and applied disclosure requirements to companies licensing data from holders of G&G permits.
After hearing industry objections to the measure, MMS published a final rule on Dec. 24, 1997, that seemed to accommodate most of the industry`s strongest objections.
A news release said the new rule "clarifies obligations of third parties who obtain data and information collected under a geological and geophysical permit, updates addresses for filing a notice or applying for a permit, standardizes definitions and archaeological requirements, and reflects changes in technology. Operators will be required to notify MMS of all scientific research activities on the Outer Continental Shelf."
MMS maintained that its right to review G&G data had always extended to third parties receiving data from permit-holders under license. But it added parts to the final rule spelling out steps to protect the confidentiality interests of companies licensing G&G data. It planned to conduct meetings with industry representatives early in 1998 to describe how it would implement the rules.
Also in 1997, the Environmental Protection Agency prevailed over bipartisan objection and resistance of its own scientific advisory body with a rule tightening standards for air pollution by ozone and small particles.
EPA Administrator Carol Browner said her initiative grew out of new indications of health problems associated with the two forms of pollution. EPA`s Clean Air Scientific Advisory Committee, however, said the indications were not conclusive.
Opponents of the measure said costs of complying with the new standards could reach $150 billion/year. They argued that the need to lower allowable levels of ozone was especially questionable since regulations already in place were reducing ozone smog in most cities. And they noted that research on the health effects of small particles (less than 2.5 microns in diameter) was limited.
Implementation of the new standards would put many urban areas of the U.S. into noncompliance with the Clean Air Act for the first time. Facing new regulation and the costs of compliance, more than 1,000 mayors and other state and local officials objected to the move, along with 250 members of Congress and 27 governors.
Clinton`s economic advisors recommended against the EPA rule. In June, however, he overruled them and supported Browner. A challenge in Congress or the courts was likely.
Among other policy developments, the Strategic Petroleum Reserve (SPR) seemed to be edging toward jeopardy in 1997. The government had tapped its inventory of crude oil several times to raise funds, and Congress in 1997 passed an appropriations bill calling for sale of $207.5 million worth of SPR oil in fiscal 1998.
The Department of Energy was preparing an administration policy statement on the SPR. It asked for public comment on whether the U.S. should continue to maintain the emergency stockpile, what the size and composition of the inventory should be, and whether SPR oil should be sold to raise government revenues.
REFining activity
Mergers, acquisitions, and other business combinations kept the refining industry in flux during 1997 as companies sought efficiency through consolidation.
Valero Energy Corp., San Antonio, took two big steps toward concentrating on its core refining business in 1997. Early in the year it agreed to sell its natural gas unit to Pacific Gas & Electric Corp. of California for $1.5 billion. It then entered an agreement to acquire Basis Petroleum Inc., a refining unit of Salomon Inc. of New York, for $285 million in Basis stock and about $200 million for inventories and other working capital. Basis operates three refineries on the Gulf Coast with capacities totaling 260,000 b/d. The refineries are at Houston, Texas City, Tex., and Krotz Springs, La.
In another major acquisition, Ultramar Diamond Shamrock Corp. agreed to take over Total Petroleum (North America) Ltd. in a deal valued at $811 million. The value included assumption by Ultramar Diamond Shamrock of $414 million of Total Petroleum debt.
The acquirer, itself the result of a 1996 merger of Diamond Shamrock Inc. and Ultramar Corp., increased its total distillation capacity to about 650,000 b/d from 500,000 b/d before the Total acquisition. Total Petroleum`s refineries were at Alma, Mich.; Ardmore, Okla.; and Denver.
Shell Oil Co. and Texaco Inc. in 1997 signed a memorandum of understanding to combine major elements of the midwestern and western U.S. refining and marketing operations and all of their U.S. transportation, trading, and lubricants businesses. A limited liability company 56% owned by Shell and 44% by Texaco was to operate the combined assets. Federal Trade Commission approval for the venture came in December after the companies agreed to sell properties in markets that they would have dominated.
Separately, USX Corp. and Ashland Inc. signed a letter of intent to combine major elements of USX-Marathon Group and Ashland`s refining, marketing, and transportation operations in a joint venture. Combined refining capacity would be 930,000 b/d. USX-Marathon was to own 62% of the venture and Ashland the rest.
Companies applied the combination strategy at the level of individual operating units. Venezuela`s Corpoven and Phillips Petroleum Co. signed a $500 million deal to build a 58,000 b/d coker at the 200,000 b/d Phillips refinery in Sweeney, Tex., and for Corpoven to supply the refinery 165,000 b/d of heavy crude for processing at Sweeney. Construction was to begin in 1998 and be complete by 2000.
Pollution-abatement costs
A study released in October 1997 by EIA traced the decline in profitability for U.S. refiners during the 1990s and concluded that requirements of the Clean Air Act Amendments of 1990 played only a minor role.
The study focused on 24 major energy companies based in the U.S., which report operating results by function to EIA under its Financial Reporting System (FRS).
It compared financial measures for 1988 and 1989, when refining and marketing (R&M) profitability was high, to the most recently available results for 1993-95, when provisions of the Clean Air Act Amendments began to take effect and be reflected in business results.
During this period, the study noted, net cash margins from U.S. R&M fell by $1.52/bbl (in 1995 dollars). The net cash margin is the gross refining margin less out-of-pocket operating costs per barrel of refined products sold. The gross margin is refined product revenues less purchases of raw material inputs to refining and product purchases.
During 1988-95, the study also noted, return on investment for R&M activities of the FRS companies fell by 12 percentage points.
EIA`s central findings: Of the $1.52/bbl decline in cash margins, increased operating costs traceable to pollution abatement accounted for 5%. And of the 12 percentage point decline in return on investment, increased capital expenditures and operating costs for pollution abatement represented slightly more than 1 percentage point, or 9% of the decrease.
Other findings in EIA`s study documented the profitability difficulties refiners had experienced throughout the 1990s.
For major U.S. oil companies, EIA said, profitability of R&M activities had lagged behind the companies` other businesses since 1986, except for 1988 and 1989. Data on returns on equity for the R&M activities of non-FSR companies, essentially independent refiners, showed a similar pattern.
Capital spending increased despite the poor profitability. FSR investment on an inflation-adjusted basis doubled during 1989-92, then fell to historic average levels in the following years. The increase mostly reflected spending on equipment to meet Clean Air Act requirements.
The only comparable surge in capital spending for refining came during the 1970s and 1980s, when companies were adding processing equipment to improve yields of light products and handle heavy, sour feedstocks.
The share of total U.S. refining capital expenditures aimed at pollution abatement increased from slightly more than 10% before the Clean Air Act Amendments of 1990 to more than 40% afterward, EIA said.
The increase in operating costs attributable to pollution abatement totaled 7¢/bbl during 1988-95.
A separate EIA study in 1997 said other market factors overwhelmed the effects on operating margins of the introduction of reformulated gasoline, one of the major requirements of the Clean Air Act Amendments.
EIA said the main influence on the net refining margin after 1988 was "a near continual decline in the spread between refined product prices and raw material input costs."
Companies reduced operating costs other than pollution abatement outlays by slightly more than $1.30/bbl during 1988-95, with most of the cuts occurring after 1992.
The reductions came from consolidations and control of expenses for energy, gasoline marketing, and other product supplies.
The FSR companies` total gross margin still dropped by nearly $2.80/bbl during the period.
Although raw material prices for inputs to refineries fell after 1988-89, prices for finished products realized by the companies declined even more.
Also hurting R&M profitability was a narrowing in the spread between prices of different-quality crudes after the companies had invested heavily in upgrading capacity.
Combined capacity of the FSR companies to process heavy, high-sulfur crude increased from 22% of total crude capacity in 1974 to 30% in 1980 and 47% in 1993, EIA said.
During the 1990s, a narrow spread between values of low and high-quality oils reduced returns to investments in upgrading capacity.
Product prices also fell in the study period. Average prices of all products were down $4/bbl (1995 dollars) in 1995 from the peak profitability years of 1988-89. The gasoline price was down, $5.14/bbl, followed by distillate, $4.83/bbl.
The composite price of other products, mainly residual and chemical feeds, was down $1.31/bbl.
Deterioration of the spread between heavy and light products hurt profitability of investments made to increase yields of light products.
REFormulated gasoline
U.S. refiners in 1997 passed a milestone in the development of reformulated gasoline (RFG), required under the Clean Air Act Amendments.
It was the last year in which they could use the so-called simple model for calculating emissions from gasoline combustion.
The Clean Air Act Amendments and related regulations in 1995 began requiring RFG in areas not meeting federal standards for ozone smog. It was the number of such areas that was certain to grow if the EPA`s tightening of standards for emissions of ozone and small particulates survived legal challenges.
The simple model for calculating gasoline emissions applied standards based on product qualities such as Reid vapor pressure (Rvp), sulfur content, benzene levels, and distillation characteristics. Some variations of it evolved for reasons of practicality.
Each model applied a baseline for determining quality limits in order to prevent dumping of low-quality feedstocks into conventional gasoline. Refiners could use their own 1990 quality baselines, established from records, or a stricter statutory baseline.
Beginning Jan. 1, 1998, refiners had to apply EPA`s phase 1 complex model, which calculated emissions according to eight parameters: oxygen, sulfur, Rvp, evaporation percentage at 200° F., evaporation percentage at 300° F., and concentrations of aromatics, olefins, and benzene.
Unlike the simple model, the complex model compared RFG quality against a statutory baseline but maintained the individual antidumping baselines for conventional gasoline.
The first-phase complex model mandated a 1.5% reduction in calculated emissions of nitrogen oxides, with sulfur the most important variable in the calculation. It also required a 16.5% cut from the 1990 baseline in emissions of identified toxic substances.
The difficulties refiners had producing complex model RFG were expected to depend on their individual baselines, which would determine the extent of changes they needed to make. In general, however, the broadening of the range of parameters was expected to increase the flexibility that RFG producers had in meeting emissions standards.
At least two companies had been producing RFG according to the complex model, which was introduced along with the simple model in 1994, before the requirement took effect.
REFiners also had to prepare for the requirement, beginning Jan. 1, 2000, for RFG made according the Phase 2 complex model.
The biggest change in Phase 2 was to be a requirement that calculated emissions of nitrogen oxides be reduced by 6.8% from the 1990 baseline. The later phase also required about a 10% cut in calculated emissions of volatile organic compounds, and a 21% reduction in emissions of toxic substances.
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